Vol. 80
Tuesday,
No. 36
February 24, 2015
Part III
Department of the Interior
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Bureau of Safety and Environmental Enforcement
30 CFR Parts 250 and 254
Bureau of Ocean Energy Management
30 CFR Part 550
Oil and Gas and Sulphur Operations on the Outer Continental Shelf—
Requirements for Exploratory Drilling on the Arctic Outer Continental Shelf;
Proposed Rule
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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules
DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental
Enforcement
30 CFR Parts 250 and 254
Bureau of Ocean Energy Management
30 CFR Part 550
[Docket ID: BSEE–2013–0011; 15XE1700DX
EX1SF0000.DAQ000 EEEE500000]
RIN 1082–AA00
Oil and Gas and Sulphur Operations
on the Outer Continental Shelf—
Requirements for Exploratory Drilling
on the Arctic Outer Continental Shelf
Bureau of Safety and
Environmental Enforcement (BSEE);
Bureau of Ocean Energy Management
(BOEM), Interior.
ACTION: Proposed rule.
AGENCY:
The Department of the
Interior (DOI), acting through BOEM
and BSEE, proposes to revise and add
new requirements to regulations for
exploratory drilling and related
operations on the Outer Continental
Shelf (OCS) seaward of the State of
Alaska (Alaska OCS). The Alaska OCS
has the potential to be an integral part
of the Nation’s ‘‘all of the above’’
domestic energy strategy. This proposed
rule focuses solely on the OCS within
the Beaufort Sea and Chukchi Sea
Planning Areas (Arctic OCS). The Arctic
region is characterized by extreme
environmental conditions, geographic
remoteness, and a relative lack of fixed
infrastructure and existing operations.
The proposed rule is designed to ensure
safe, effective, and responsible
exploration of Arctic OCS oil and gas
resources, while protecting the marine,
coastal, and human environments, and
Alaska Natives’ cultural traditions and
access to subsistence resources.
DATES: Submit comments by April 27,
2015. BOEM and BSEE may not fully
consider comments received after this
date. You may submit comments to the
Office of Management and Budget
(OMB) on the information collection
burden in this proposed rule by March
26, 2015. The deadline for comments on
the information collection burden does
not affect the deadline for the public to
comment to BOEM and BSEE on the
proposed regulations.
ADDRESSES: You may submit comments
on the rulemaking by any of the
following methods. For comments on
this proposed rule, please use
Regulation Identifier Number (RIN)
1082–AA00 in your message. For
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SUMMARY:
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comments specifically related to the
draft Environmental Assessment
conducted under the National
Environmental Policy Act of 1969
(NEPA), please refer to NEPA in the
heading of your message. See also,
Public Availability of Comments under
Procedural Matters.
• Federal eRulemaking Portal: http://
www.regulations.gov. In the Search box,
enter BSEE–2013–0011, then click
search. Follow the instructions to
submit public comments and view
supporting and related materials
available for this rulemaking. BOEM
and BSEE will post all submitted
comments.
• Mail or hand-carry comments to the
DOI, BSEE: Attention: Regulations and
Standards Branch, 381 Elden Street,
HE3314, Herndon, Virginia 20170–4817.
Please reference ‘‘Oil and Gas and
Sulphur Operations on the Outer
Continental Shelf—Requirements for
Exploratory Drilling on the Arctic Outer
Continental Shelf,’’ 1082–AA00 in your
comments, and include your name and
return address.
• Send comments on the information
collection of this rule to: Interior Desk
Officer 1082–AA00, Office of
Management and Budget; 202–395–5806
(fax); email: OIRA_Submission@
omb.eop.gov. Please also send copies to
BSEE by one of the means previously
described.
FOR FURTHER INFORMATION CONTACT:
Mark E. Fesmire, BSEE, Alaska Regional
Office, mark.fesmire@bsee.gov, (907)
334–5300; John Caplis, BSEE, Oil Spill
Response Division, john.caplis@
bsee.gov, (703) 787–1364; or David
Johnston, BOEM, Alaska Regional
Office, david.johnston@boem.gov, (907)
334–5200. To see a copy of either
information collection request
submitted to OMB, go to http://
www.reginfo.gov (select Information
Collection Review, Currently Under
Review).
SUPPLEMENTARY INFORMATION:
Executive Summary
Although there is currently a
comprehensive OCS oil and gas
regulatory program, DOI engagement
with stakeholders reveals the need for
new and revised regulatory measures for
exploratory drilling conducted by
floating drilling vessels and ‘‘jackup
rigs’’ (collectively known as mobile
offshore drilling units or MODUs) on
the Arctic OCS. The United States (U.S.)
Arctic region, as recognized by the U.S.
and defined in the U.S. Arctic Research
and Policy Act of 1984, encompasses an
extensive marine and terrestrial area,
but this proposed rule focuses solely on
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the OCS within the Beaufort Sea and
Chukchi Sea Planning Areas.
BOEM and BSEE have undertaken
extensive environmental and safety
reviews of potential oil and gas
operations on the Arctic OCS. These
reviews, along with concerns expressed
by environmental organizations and
Alaska Natives, reinforce the need to
develop additional measures
specifically tailored to the operational
and environmental conditions of the
Arctic OCS. After considering the input
provided by various stakeholders and
DOI’s direct experience from Shell’s
2012 Arctic operations, BOEM and
BSEE have concluded that additional
exploratory drilling regulations would
enhance existing regulations and would
be appropriate for a more holistic Arctic
OCS oil and gas regulatory framework.
This proposed rulemaking is intended
to provide regulations to ensure Arctic
OCS exploratory drilling operations are
conducted in a safe and responsible
manner that would take into account the
unique conditions of Arctic OCS
drilling and Alaska Natives’ cultural
traditions and need to access
subsistence resources. The Arctic region
is known for its oil and gas resource
potential, its vibrant ecosystems, and
the Alaska Native communities, who
rely on the Arctic’s resources for
subsistence and cultural traditions. The
region is characterized by extreme
environmental conditions, geographic
remoteness, and a relative lack of fixed
infrastructure and existing operations.
These are key factors in considering the
feasibility, practicality, and safety of
conducting offshore oil and gas
activities on the Arctic OCS.
This proposed rule would add to, and
revise existing regulations in, 30 CFR
parts 250, 254, and 550 for Arctic OCS
oil and gas activities. The proposed rule
would focus on Arctic OCS exploratory
drilling activities that use MODUs and
related operations during the Arctic
OCS open-water drilling season. This
proposed rule would address a number
of important issues and objectives,
including ensuring that each operator:
1. Designs and conducts exploration
programs in a manner suitable for Arctic
OCS conditions;
2. Develops an integrated operations
plan (IOP) that would address all phases
of its proposed Arctic OCS exploration
program and submit the IOP to DOI,
acting through its designee, BOEM, at
least 90 days in advance of filing the
Exploration Plan (EP);
3. Has access to, and the ability to
promptly deploy, Source Control and
Containment Equipment (SCCE) while
drilling below, or working below, the
surface casing;
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4. Has access to a separate relief rig
located so that it could timely drill a
relief well in the event of a loss of well
control under the conditions expected at
the site;
5. Has the capability to predict, track,
report, and respond to ice conditions
and adverse weather events;
6. Effectively manages and oversees
contractors; and
7. Develops and implements an Oil
Spill Response Plan (OSRP) that is
designed and executed in a manner
suitable for the unique Arctic OCS
operating environment and has the
necessary equipment, training, and
personnel for oil spill response on the
Arctic OCS.
The proposed rule would further the
Nation’s interest in exploring frontier
areas, such as those in the Arctic region,
and would establish specific operating
models and requirements for the
extreme, changing conditions that exist
on the Arctic OCS. The proposed
regulations would require
comprehensive planning of operations,
especially for emergency response and
safety systems. The proposed rule
would seek to institutionalize a
proactive approach to offshore safety. A
goal of the proposed rule is to identify
possible vulnerabilities early in the
planning process so that corrections
could be made in order to decrease the
possibility of an incident occurring. The
requirements in the proposed rule are
also designed to ensure that those plans
would be executed in a safe and
environmentally protective manner
despite the challenges presented by the
Arctic.
Table of Contents
List of Acronyms and References
I.
Introduction
A. Resource Potential
B. Integrated Arctic Management
C. Overview of Proposed Regulations
D. Potential Costs and Benefits of
Proposed Rule
II. Background
A. Statutory and Regulatory Overview
B. Factual Overview of the Alaska OCS
Region
C. Partner and Stakeholder Engagement
in Preparation for This Proposed Rule
D. Expected Benefits Justifying Potential
Costs
III. Proposed Regulations for Arctic OCS
Exploratory Drilling
A. Measures That Address
Recommendations
B. IOP Requirement
C. SCCE and Relief Rig Capabilities
D. Planning for the Variability and
Challenges of the Arctic OCS Conditions
E. Arctic OCS Oil Spill Response
Preparedness
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F.
Reducing Pollution From Arctic OCS
Exploratory Drilling Operations
G. Oversight, Management, and
Accountability of Operations and
Contractor Support
IV. Section-By-Section Discussion
A. Definitions (§§ 250.105, 254.6, and
550.105)
B. Additional Regulations Proposed by
BOEM
C. Additional Regulations Proposed by
BSEE
D. Arctic Exploratory Drilling Process
Flowchart
V. Conclusion
VI. Procedural Matters
A. Regulatory Planning and Review (E.O.
12866 and E.O. 13563)
B. E.O. 12866
C. E.O. 13563
D. Regulatory Flexibility Act
E. Unfunded Mandates Reform Act of
1995 (UMRA)
F. Takings Implication Assessment
G. Federalism (E.O. 13132)
H. Civil Justice Reform (E.O. 12988)
I. Consultation With Indian Tribes (E.O.
13175)
J. E.O. 12898
K. Paperwork Reduction Act (PRA)
L. National Environmental Policy Act of
1969 (NEPA)
M. Data Quality Act
N. Effects on the Nation’s Energy Supply
(E.O. 13211)
O. Clarity of Regulations
P. Public Availability of Comments
LIST OF ACRONYMS AND REFERENCES
60-Day report
Report to the Secretary of the Interior, review
of Shell’s 2012 Alaska offshore oil and gas
exploration program
MODU
Mobile offshore drilling units
AIS ...............................
Automatic Identification System ......................
NARA .........................
Alaska OCS .................
OCS Seaward of the State of Alaska .............
ANCSA ........................
APD .............................
Alaska Native Claims Settlement Act .............
Application for Permit to Drill ..........................
National Arctic Strategy.
NEPA ..........................
NOAA .........................
API ...............................
American Petroleum Institute ..........................
NPDES .......................
APM .............................
Arctic OCS ...................
OCS ............................
OCSLA .......................
OMB ...........................
OPA ............................
OSRP .........................
PPCS ..........................
PRA ............................
Office of Management and Budget.
Oil Pollution Act of 1990.
Oil Spill Response Plan.
Pre-Positioned Capping Stack.
Paperwork Reduction Act.
RFA ............................
RIA .............................
RIN .............................
ROV ............................
Regulatory Flexibility Act.
Regulatory Impact Analysis.
Regulation Identifier Number.
Remotely Operated Vehicle.
DOI ..............................
DPP .............................
EA ................................
E.O. .............................
Application for Permit to Modify ......................
OCS within the Beaufort Sea and Chukchi
Sea Planning Areas.
Audit Service Provider ....................................
Bureau of Ocean Energy Management ..........
Blowout Preventer ...........................................
BP Exploration (Alaska), Inc. ..........................
Bureau of Safety and Environmental Enforcement.
Corrective Action Plan ....................................
Code of Federal Regulations ..........................
Clean Water Act ..............................................
Development Operations Coordination Documents.
Department of the Interior ...............................
Development and Production Plans ...............
Environmental Assessment ............................
Executive Order ..............................................
National Archives and Records Administration.
President’s National Strategy for the Arctic
Region issued May 2013.
National Environmental Policy Act of 1969.
National Oceanic and Atmosphere Administration.
National Pollutant Discharge Elimination System.
Outer Continental Shelf.
Outer Continental Shelf Lands Act.
RP ..............................
SCCE .........................
Secretary ....................
SEMS .........................
EP ................................
EPA .............................
ESA .............................
IC .................................
Exploration Plan ..............................................
Environmental Protection Agency ...................
Endangered Species Act ................................
Information Collection .....................................
SIDs ............................
UMRA .........................
U.S. ............................
USCG .........................
Recommended Practice.
Source Control and Containment Equipment.
Secretary of the Interior.
Safety and Environmental Management Systems.
Shut-in Devices.
Unfunded Mandates Reform Act of 1995.
United States.
U.S. Coast Guard.
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ASP .............................
BOEM ..........................
BOP .............................
BP ................................
BSEE ...........................
CAP .............................
CFR .............................
CWA ............................
DOCD ..........................
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LIST OF ACRONYMS AND REFERENCES—Continued
60-Day report
Report to the Secretary of the Interior, review
of Shell’s 2012 Alaska offshore oil and gas
exploration program
MODU
Mobile offshore drilling units
ICAS ............................
Initial RIA .....................
IOP ..............................
Inupiat Community of the Arctic Slope ...........
Initial Regulatory Impact Analysis ...................
Integrated Operations Plan .............................
USFWS ......................
WCD ...........................
Working Group ...........
U.S. Fish and Wildlife Service.
Worst-Case Discharge.
Interagency Working Group on Coordination
of Domestic Energy Development and Permitting in Alaska.
ISO ..............................
International Organization for Standardization.
I. Introduction
The Arctic region is known for its oil
and gas resource potential, its thriving
and diverse ecosystems, and the Alaska
Native communities who rely on the
Arctic’s resources for subsistence and
cultural traditions. The Arctic region is
also characterized by extreme
environmental conditions, geographic
remoteness, and a relative lack of fixed
infrastructure and existing operations.
These are key factors in considering the
feasibility, practicality, and safety of
conducting offshore oil and gas
activities on the Arctic OCS.
In May 2013, President Obama issued
a document entitled, ‘‘National Strategy
for the Arctic Region (National Arctic
Strategy).’’ The President affirmed that
emerging economic opportunities exist
in the region, but that ‘‘ . . . we must
exercise responsible stewardship, using
an integrated management approach and
making decisions based on the best
available information, with the aim of
promoting healthy, sustainable, and
resilient ecosystems over the long
term.’’
In keeping with the Nation’s
comprehensive ‘‘all of the above’’
energy strategy to continue to expand
safe and responsible domestic energy
production, the National Arctic Strategy
is intended, among other things, to
‘‘reduce our reliance on imported oil
and strengthen our Nation’s energy
security’’ by working with stakeholders
to enable ‘‘environmentally responsible
production of oil and natural gas.’’ To
provide responsible stewardship of the
Arctic’s environment and resources, the
National Arctic Strategy emphasizes the
need for integrated and balanced
management techniques.
Furthermore, the National Arctic
Strategy acknowledges the potential
international implications of Arctic oil
and gas activities for ‘‘other Arctic states
and the international community as a
whole.’’ The U.S. has committed to do
its part to ‘‘keep the Arctic region
prosperous, environmentally
sustainable, operationally safe, secure,
and free of conflict[.]’’ One primary
objective outlined in the
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implementation plan for the National
Arctic Strategy is to ‘‘reduce the risk of
marine oil pollution while increasing
global capabilities for preparedness and
response to oil pollution incidents in
the Arctic.’’ (http://
www.whitehouse.gov/sites/default/files/
docs/implementation_plan_for_the_
national_strategy_for_the_arctic_region_
-_fi....pdf). The National Arctic Strategy
is an example of the types of action the
U.S. is taking to implement its
obligations under international
agreements, such as the Arctic Council’s
Agreement on Cooperation on Marine
Oil Pollution Preparedness and
Response in the Arctic (available at:
www.arctic-council.org/eppr/agreementon-cooperation-on-marine-oil-pollutionpreparedness-and-response-in-thearctic/).
A. Resource Potential
The Alaska OCS region is estimated to
contain a vast amount of undiscovered,
technically recoverable oil and gas.
According to BOEM’s 2011 Assessment
of Undiscovered Technically
Recoverable Oil and Gas Resources of
the Nation’s Outer Continental Shelf
(mean estimates available at:
www.boem.gov/Oil-and-Gas-EnergyProgram/Resource-Evaluation/ResourceAssessment/2011_National_
Assessment_Factsheet-pdf.aspx), there
are approximately 23.6 billion barrels of
technically recoverable oil and about
104.4 trillion cubic feet of technically
recoverable natural gas in the Beaufort
Sea and Chukchi Sea Planning Areas
combined. Most of the Alaska OCS
resource potential is located off the
Arctic coast within the Chukchi Sea and
Beaufort Sea Planning Areas. This
resource potential has received
considerable attention from the oil and
gas industry and the U.S. government,
and has precipitated the sale of
hundreds of leases and the initiation of
subsequent exploration activities. The
Alaska OCS region, particularly the
Beaufort Sea and Chukchi Sea Planning
Areas, has the potential to be an integral
part of the ‘‘all of the above’’ domestic
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energy strategy articulated in the
National Arctic Strategy.
B. Integrated Arctic Management
As ocean and seasonal conditions
continue to change in the Arctic, there
will be an increasing number of
stakeholders vying for access to the
Arctic OCS and the waters above it.
Both commercial and recreational
activities are increasing as more areas of
water open up for longer periods of time
due to the increase of melting sea ice.
The decrease in summer sea ice raises
legitimate concerns regarding changes to
the environment and the Arctic
resources that Alaska Natives depend on
for survival and cultural traditions.
Consistent with the Outer Continental
Shelf Lands Act (OCSLA), BOEM and
BSEE, the Bureaus responsible for
managing oil and gas resources on the
Arctic OCS, are proposing regulations
that take into account the needs of the
multiple users who have an interest in
the future of the U.S. Arctic region (see
43 U.S.C. 1332(6)).
The U.S. has maintained a
longstanding interest in the orderly
development of oil and gas resources on
the Arctic OCS, while also seeking to
ensure the protection of its environment
and communities. The U.S. has
proceeded cautiously to ensure that
laws, regulations, and policies
concerning Arctic OCS oil and gas
development are created and
implemented based on a thorough
examination of the multiple factors at
play in the unique Arctic environment.
BOEM and BSEE have conducted
extensive research on potential oil and
gas activities in the Arctic OCS in
anticipation of operations (see, e.g.,
www.bsee.gov/Technology-andResearch/Technology-AssessmentPrograms/Categories/Arctic-Research/),
and have also evaluated the potential
environmental effects of such activities
(see, e.g., http://www.boem.gov/
akstudies/). These research projects,
along with other initiatives, form the
basis for the most recent National
policies and directives regarding Alaska
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OCS oil and gas development, all of
which have guided this proposed rule.
Coordinating the future uses of the
Arctic region will require integrated
action between and among Federal,
state, and tribal governmental entities.
On July 15, 2011, President Obama
signed Executive Order (E.O.) 13580,
establishing an Interagency Working
Group on Coordination of Domestic
Energy Development and Permitting in
Alaska (Working Group), chaired by the
Deputy Secretary of DOI. The Working
Group is composed of representatives
from the DOI, Department of Defense,
Department of Commerce, Department
of Agriculture, Department of Energy,
Department of Homeland Security, the
Environmental Protection Agency
(EPA), and the Office of the Federal
Coordinator for Alaska Natural Gas
Transportation Projects. It is charged
with facilitating ‘‘coordinated and
efficient domestic energy development
and permitting in Alaska while ensuring
that all applicable [health, safety, and
environmental protection] standards are
fully met’’ (E.O. 13580, sec. 1).
The Working Group was involved in
coordinating Federal regulatory and
oversight efforts for the 2012 Alaska
OCS drilling season and played an
important role in BOEM’s and BSEE’s
reviews of plans and permits for Shell’s
2012 operations. The Working Group’s
report entitled, ‘‘Managing for the
Future in a Rapidly Changing Arctic, A
Report to the President’’ (March 2013),
was the result of substantial
collaboration and has also played a
significant role in shaping U.S. Arctic
policies.
C. Overview of Proposed Regulations
Although there is currently a
comprehensive OCS oil and gas
regulatory program, DOI engagement
with partners and stakeholders 1 reveals
the need for new and enhanced
regulatory measures for Arctic OCS
exploratory drilling by MODUs. For
purposes of this rulemaking, exploratory
drilling is considered to be ‘‘[a]ny
drilling conducted for the purpose of
searching for commercial quantities of
oil, gas, and sulphur, including the
drilling of any additional well needed to
delineate any reservoir to enable the
lessee to decide whether to proceed
with development and production’’ (30
CFR 250.105 and 30 CFR 550.105 (one
of the definitions of ‘‘exploration’’)).2
1 Tribes, State and local governments, and Federal
agencies are ‘‘partners.’’ ‘‘Stakeholders’’ are nongovernmental organizations, industry, and other
entities.
2 This proposed rule uses and defines terms that
may be similar to terms used in other programs by
other Federal agencies; however, the terms and
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This proposed rule focuses on Arctic
OCS exploratory drilling activities that
use MODUs (e.g., jack-ups and anchored
drillships) and related operations during
the Arctic open-water drilling season
(generally late June to early November).
After the requirements for exploratory
drilling are finalized and applied to
those activities, DOI will be able to
assess whether it should apply similar
requirements to development drilling.
BOEM and BSEE will then be in a
position to consider developing
requirements appropriate for
development drilling activities and
publish a rulemaking for public notice
and comment in the Federal Register.
The requirements may be the same as
the final requirements for exploratory
drilling, or BOEM and BSEE may
modify these requirements.
The Arctic region is known for its
challenging environmental conditions,
geographic remoteness, and relative lack
of existing infrastructure. This proposed
rule builds on and would codify input
received from partners and
stakeholders, key components of Shell’s
2012 Arctic exploratory drilling
program, as well as the additional
measures DOI required to ensure Shell’s
drilling operations were conducted
safely.
Though its actual drilling operations
were conducted without incident, Shell
experienced a number of challenges
during its 2012 exploratory drilling
program. In 2013, DOI released a
‘‘Report to the Secretary of the Interior,
Review of Shell’s 2012 Alaska Offshore
Oil and Gas Exploration Program’’ (60Day Report) (available at: http://
www.doi.gov/news/pressreleases/
upload/Shell-report-3-8-13-Final.pdf).
The 60-Day Report identified a number
of lessons learned and recommended
practices to ensure future Arctic oil and
gas exploration activities continue to be
carried out in a safe and responsible
manner.
BOEM and BSEE have undertaken
extensive environmental and safety
reviews of potential oil and gas
operations on the Arctic OCS. These
reviews, along with concerns expressed
by environmental organizations and
Alaska Natives, reinforce the need to
develop additional measures
specifically tailored to the operational
and environmental conditions of the
Arctic OCS. Arctic OCS operations can
be complex, and there are challenges
and operational risks throughout every
phase of an exploratory drilling
definitions used in this proposed rule are intended
to apply only to the BSEE and BOEM regulatory
programs covered by this proposed rule, unless
otherwise noted.
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program. Experience gained during the
2012 Arctic drilling season has led
BOEM and BSEE staff to conclude that
enhanced and more specific
requirements can help ensure that oil
and gas activities in the Arctic OCS are
conducted in a safe and
environmentally responsible manner.
After considering the input provided by
various stakeholders and DOI’s direct
experience from Shell’s 2012 Arctic
operations, BOEM and BSEE have
concluded that additional exploratory
drilling regulations are necessary and
appropriate as a part of the Arctic OCS
oil and gas regulatory framework.
This proposed rule is a combination
of prescriptive and performance-based
requirements that address a number of
important issues and objectives,
including, but not limited to, ensuring
that operators:
1. Design and conduct exploration
programs in a manner suitable for Arctic
OCS Conditions (e.g., using equipment
and processes that are capable of
performing effectively and safely under
extreme weather and sea conditions and
in remote locations with relatively
limited infrastructure);
2. Develop an IOP that would address
all phases of their proposed Arctic OCS
exploration program and submit the IOP
to DOI, acting through its designee,
BOEM, at least 90 days in advance of
filing the EP;
3. Have access to, and the ability to
promptly deploy, SCCE while drilling
below or working below the surface
casing;
4. Have access to a separate relief rig
located so that it could timely drill a
relief well in the event of a loss of well
control under the conditions expected at
the site;
5. Have the capability to predict,
track, report, and respond to ice
conditions and adverse weather events;
6. Effectively manage and oversee
contractors; and
7. Develop and implement OSRPs that
are designed and executed in a manner
suitable for the unique Arctic OCS
operating environment and that describe
the availability of the necessary
equipment, training, and personnel for
oil spill response on the Arctic OCS.
D. Potential Costs and Benefits of
Proposed Rule
The Initial Regulatory Impact
Analysis (RIA) for this proposed rule
estimates that, if implemented as
proposed, the new regulations would
result in economic costs ranging from
$1.1 to 1.2 billion (at discount rates of
7 percent and 3 percent, respectively)
over 10 years. The above estimated cost
range reflects the increase in costs over
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the baseline costs. As discussed in part
VI.B.3, the baseline is calculated by
estimating the costs associated with
current regulatory requirements and
industry standards. In general, this
includes the requirements imposed by
DOI during the 2012 drilling season.
However, even though DOI required the
availability of a relief rig in 2012, we
have conservatively chosen not to
include the costs of staging a standby
relief rig in the baseline. Although
BOEM and BSEE expect that over time,
as the number of operating rigs on the
Arctic OCS increases, operators will use
a second operating rig as a relief rig, in
lieu of a dedicated standby relief rig, we
have included the capital and activity
costs for a standby rig for the first two
years (2015–2016) of the 10-year time
period in the economic costs of the
proposed rule.
While the economic and other
benefits of the proposed rule—based
primarily on preventing or reducing the
severity or duration of catastrophic oil
spills—are difficult to quantify, BOEM
and BSEE have determined that it is
appropriate to proceed with this
proposal. Although the probability of a
catastrophic oil spill is low, the
Deepwater Horizon oil spill
demonstrated that even such low
probability events can have devastating
economic and environmental results
when they occur. The benefits of the
proposed rule include reducing such
risks associated with Arctic offshore
operations.
Reducing the risks of Arctic offshore
operations is particularly important
because of the unique significance to
Alaska Natives of the fish and marine
mammals in the lands and waters
around the Arctic OCS; those resources
are critical components of the Alaska
Natives’ livelihood, and they rely on
fishing and hunting for traditional
cultural purposes and for subsistence.
Similarly, many other Americans place
a very high value on protecting the
health of the ecosystem, including the
sensitive environment and wildlife, of
this largely frontier area. Thus, the
impact of a catastrophic oil spill, while
a remote possibility, would have
extremely high cultural and societal
costs, and prevention of such a
catastrophe would have
correspondingly high cultural and
societal benefits.
The proposed requirements—
specifically tailored to the Arctic OCS—
would provide additional specificity
regarding BOEM’s and BSEE’s
expectations for safe and responsible
development of Arctic resources and
would outline the particular actions that
lessees, owners and operators must take
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in order to meet those expectations.
BSEE and BOEM do not anticipate that
these proposed requirements, or their
associated costs, would prevent lessees
and operators from conducting
exploratory drilling on their leases. In
fact, the additional clarity and
specificity provided by the proposed
rule should help the oil and gas
industry to plan better and to more
effectively conduct exploratory drilling
on the Arctic OCS, which in turn should
result in development and production of
oil and gas with lower risk and fewer
delays than under the current rules.
Since the potential economically
recoverable oil and gas resources from
the Arctic OCS are abundant, as
discussed later in this proposed rule,
the positive impact of such production
on U.S. energy independence and
energy security could be substantial.
Thus, this proposed rule would help
achieve the National Arctic Strategy
goals of protecting the unique and
sensitive Arctic ecosystems, as well as
the subsistence, culture and traditions
of the Alaska Native communities,
while reducing reliance on imported oil
and strengthening National energy
security.
II. Background
A. Statutory and Regulatory Overview
1. Outer Continental Shelf Lands Act
(OCSLA)
The OCSLA, 43 U.S.C. 1331 et seq.,
was first enacted in 1953, and
substantially amended in 1978, when
Congress established a National policy
of making the OCS ‘‘available for
expeditious and orderly development,
subject to environmental safeguards, in
a manner which is consistent with the
maintenance of competition and other
National needs’’ (43 U.S.C. 1332(3)). In
addition, Congress emphasized the need
to develop OCS mineral resources in a
safe manner ‘‘by well-trained personnel
using technology, precautions, and
techniques sufficient to prevent or
minimize the likelihood of blowouts,
loss of well control, fires, spillages,
physical obstruction to other users of
the waters or subsoil and seabed, or
other occurrences which may cause
damage to the environment or to
property, or endanger life or health’’ (43
U.S.C. 1332(6)). The Secretary of the
Interior (Secretary) administers the
OCSLA’s provisions relating to the
leasing of the OCS and regulation of
mineral exploration and development
operations on those leases. The
Secretary is authorized to prescribe
‘‘such rules and regulations as may be
necessary to carry out [OCSLA’s]
provisions . . . and may at any time
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prescribe and amend such rules and
regulations as [s]he determines to be
necessary and proper in order to
provide for the prevention of waste and
conservation of the natural resources of
the [OCS] . . .’’ which ‘‘shall, as of their
effective date, apply to all operations
conducted under a lease issued or
maintained under the provisions of
[OCSLA]’’ (43 U.S.C. 1334(a)).
Prior to commencing exploration for
oil and gas on an OCS lease tract, the
statute and BOEM regulations require
lessees to submit an EP to the Secretary
for approval (43 U.S.C. 1340(c)(1); 30
CFR 550.201(a)). An EP must include
information such as a schedule of
anticipated exploration activities,
equipment to be used, the general
location of each well to be drilled, and
any other information deemed pertinent
by the Secretary (43 U.S.C. 1340(c)(3);
30 CFR 550.211 through 550.228)).
However, approval of an EP does not
automatically permit the lessee to
proceed with exploratory drilling. The
lessee must submit to the Secretary an
Application for Permit to Drill (APD)
which must be approved before a lessee
may drill a well (43 U.S.C. 1340(d); 30
CFR 250.410).
The Secretary delegated most of the
responsibilities under the OCSLA to
BOEM and BSEE, both of which are
charged with administering and
regulating aspects of the Nation’s OCS
oil and gas program. BOEM and BSEE
work to promote safety, protect the
environment, and conserve offshore
resources through vigorous regulatory
oversight. BOEM manages the
development of the Nation’s offshore
energy resources in an environmentally
and economically responsible way.
BOEM’s functions include leasing;
exploration, development and
production plan administration;
environmental analyses to ensure
compliance with NEPA; environmental
studies; resource evaluation; economic
analysis; and management of the OCS
renewable energy program. BSEE
performs offshore regulatory oversight
and enforcement to ensure safety and
environmentally sound performance
during operations, and the conservation
of offshore resources, by, among other
things, evaluating drilling permits, and
conducting inspections to ensure
compliance with laws, regulations, lease
terms, and approved plans and permits.
BOEM evaluates EPs, and BSEE
evaluates APDs, to determine whether
the operator’s proposed activities meet
the OCSLA’s standards and each
Bureau’s regulations governing offshore
exploration. The regulatory
requirements include, but are not
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2. The Oil Pollution Act of 1990 (OPA)
and Clean Water Act (CWA)
Congress passed the OPA, 33 U.S.C.
2701 et seq., following the Exxon Valdez
oil spill. The OPA amended the CWA,
33 U.S.C. 1251 et seq., by, among other
things, adding OSRP provisions for
offshore facilities. The OPA provides for
prompt federally coordinated responses
to offshore oil spills and for
compensation of spill victims. It also
calls for the issuance of regulations
prohibiting owners and operators of
offshore facilities from operating or
handling, storing, or transporting oil
until:
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i. They have prepared and submitted
‘‘a plan for responding, to the maximum
extent practicable, to a worst case
discharge, and to a substantial threat of
such a discharge, of oil . . .;’’
ii. The plan ‘‘has been approved by
the President;’’ and
iii. The ‘‘facility is operating in
compliance with the plan’’ (OPA
§ 4202(a), codified at 33 U.S.C.
1321(j)(5)(A)(i) and (F)(i)–(ii)).
E.O. 12777 (October 18, 1991)
authorized the Secretary to carry out the
functions of 33 U.S.C. 1321(j)(5) and
(j)(6)(A). This includes the promulgation
of regulations governing the obligation
to prepare and submit OSRPs, the
review and approval of OSRPs, and the
periodic verification of spill response
capabilities related to these plans. Those
applicable regulations are administered
by BSEE and are found at 30 CFR parts
250 and 254. E.O. 12777 also authorized
the Secretary to implement 33 U.S.C.
1321(j)(1)(C), which provides for the
issuance of regulations ‘‘establishing
procedures, methods, and equipment
and other requirements for equipment to
prevent discharges of oil and hazardous
substances from . . . offshore facilities,
and to contain such discharges. . . .’’
B. Factual Overview of the Alaska OCS
Region
1. The Arctic OCS Oil and Gas Resource
Potential Has Attracted Significant
Attention Over the Past Three Decades
There has been a renewed interest in
the oil and gas potential of the Alaska
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OCS since the first exploratory wells
were drilled in the late 1970s. The
majority of exploratory drilling north of
the Arctic Circle has occurred where the
greatest oil and gas resource potential
exists, namely the Beaufort Sea and
Chukchi Sea Planning Areas (defined in
this proposed rule as the Arctic OCS).
A total of 30 exploratory wells have
been drilled on the Beaufort OCS since
the first Federal OCS leases were
offered, and more wells have been
drilled beneath the near-shore Beaufort
Sea under the jurisdiction of the State
of Alaska (see BOEM Alaska Region
Web site at: http://www.boem.gov/
About-BOEM/BOEM-Regions/AlaskaRegion/Historical-Data/Index.aspx). The
Chukchi Sea Planning Area has a more
limited history of leasing and
exploration. Only a total of five
exploratory wells have been drilled (see
BOEM Alaska Region Web site at:
www.boem.gov/About-BOEM/BOEMRegions/Alaska-Region/Historical-Data/
Index.aspx) and no site was considered
commercially viable for development
during that time.
There have been only three
exploratory wells drilled on the Arctic
OCS since 1994—the 2003 exploratory
well near Prudhoe Bay in the Beaufort
Sea and Shell’s two ‘‘top hole’’ wells
drilled in 2012 (see BOEM Assessment
of Undiscovered Technically
Recoverable Oil and Gas Resources of
the Nation’s Outer Continental Shelf
(2011)).
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limited to, determining whether the
proposed drilling operation:
i. Conforms to OCSLA, as amended,
its applicable implementing regulations,
lease provisions and stipulations, and
other applicable laws;
ii. Is safe;
iii. Conforms to sound conservation
practices and protects the rights of the
U.S. and mineral resources of the OCS;
iv. Does not unreasonably interfere
with other uses of the OCS; and
v. Does not cause undue or serious
harm or damage to the human, marine,
or coastal environments (30 CFR
250.101 and 250.106; 30 CFR 550.101
and 550.202).
Based on these evaluations, BOEM
and BSEE will approve the lessee’s (or
operator’s) EP and APD, require the
lessee (or operator) to modify its
submissions, or disapprove the EP or
APD (30 CFR 250.410; 30 CFR 550.233).
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Except for the Northstar project,
operated by BP Exploration (Alaska),
Inc. (BP) from State submerged lands in
the Beaufort Sea, no production has yet
resulted from any of the leases.3
There are currently no active Alaska
OCS leases located anywhere outside of
the Beaufort Sea and Chukchi Sea
Planning Areas. The oil and gas
industry’s interest in offshore oil and
gas exploration on the Arctic OCS
remains high despite the pace of
exploration and the challenges of
operating in this unique environment.
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2. Challenges to Arctic Oil and Gas
Operations
The challenges to conducting
operations and responding to
emergencies in the extreme and variable
environmental and weather conditions
in the Arctic are severe. Both the
Beaufort Sea and Chukchi Sea Planning
Areas experience sub-freezing
temperatures during most of the year,
extended periods of low-light visibility,
significant fog cover in the summer,
strong winds and currents, strong
storms that produce freezing spray and
dangerous sea states, snow, and
significant ice cover. During the fall
(September–November), conditions
become increasingly inhospitable as air
temperatures decrease, wind speeds
increase, storms become more frequent,
and sea ice begins to form, all of which
make Arctic OCS exploratory drilling
operations more challenging (see
Environmental Assessments for Shell
Offshore, Inc.’s Revised Outer
Continental Shelf Lease Exploration
Plan, Camden Bay, Beaufort Sea, Alaska
(2011) and Shell Gulf of Mexico, Inc.’s
Revised Chukchi Sea Exploration Plan
Burger Prospect (2011)); BOEM Alaska
Region Web site at: http://www.boem.
gov/About-BOEM/BOEM-Regions/
Alaska-Region/Environment/
Environmental-Analysis/EnvironmentalImpact-Statements-and—MajorEnvironmental-Assessments.aspx).
Other challenges to conducting
operations and responding to
emergencies on the Arctic OCS include
the geographical remoteness and
relative lack of established
infrastructure to support oil and gas
operations.
C. Partner and Stakeholder Engagement
in Preparation for This Proposed Rule
DOI used the recommendations from
the 60-Day Report as a basis for a series
of discussions with multiple partners
and stakeholders who provided valuable
3 BP has transferred its interests in the Northstar
project to Hilcorp. Hilcorp is now the operator of
that project.
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input regarding potential approaches to
regulating oil and gas operations on the
Arctic OCS. BOEM and BSEE recognize
the importance of the Arctic region to a
number of partners and stakeholders
with varying positions on oil and
natural gas development in the region.
Both Bureaus engaged in discussions
with Alaska Native and State partners,
and with environmental and industry
stakeholders, in advance of publishing
this proposed rule. Those discussions
addressed the recommendations from
the 60-Day Report, as well as
information regarding operating
conditions and challenges in the Arctic.
The then-Acting Assistant Secretary for
Land and Minerals Management, along
with DOI staff from headquarters and
the Alaska Region, held three listening
sessions and a series of meetings in
Alaska over the course of several weeks
in June 2013. Representatives of DOI
also met with conservation
organizations, the Mayor of the North
Slope Borough, the Alaska Eskimo
Whaling Commission, the Inupiat
Community of the Arctic Slope (ICAS),
the Native Village of Barrow, two Alaska
Native Claims Settlement Act (ANCSA)
corporations, oil and gas industry
representatives, State of Alaska officials,
and other local government
representatives.
DOI considered the suggestions and
concerns of all partners and
stakeholders to produce a proposed rule
that balances maximizing oil and gas
resource exploration on the Arctic OCS,
in furtherance of the Nation’s energy
security, with appropriate safeguards to
protect human safety and the unique
Arctic environment, as well as the
cultural sensitivities and subsistence
needs of the Alaska Native communities
that might be affected by oil and gas
development in the Arctic.
1. Alaska Natives
DOI heard a variety of perspectives
from Alaska Natives during its outreach
in advance of the rulemaking, including
interest in the potential economic
opportunities from oil and gas
development. However, the overriding
concern expressed by Alaska Natives is
the potential for adverse impacts from
oil and gas operations on the marine
environment and its resources,
including marine mammals, such as
bowhead whales. Alaska Natives
requested that the DOI evaluate the
extent to which oil and gas activities
may adversely affect marine resources of
the waters overlying the Arctic OCS and
the subsistence harvest practices of
Alaska Natives. In particular, the marine
mammal fauna of the Beaufort and
Chukchi Seas are among the most
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diverse in the world and are of high
scientific and public interest, and many
are also important for subsistence.
Future exploratory drilling could
affect subsistence users in the Arctic
region. Subsistence harvests differ
among Alaska Native coastal
communities. However, the bowhead
whale is the most important marine
mammal species to a majority of Arctic
coastal communities because it is the
preferred meat and it provides a unique
and powerful cultural basis for sharing
and community cooperation.
Subsistence practices are a highly
valued aspect of Alaska Native culture.
These practices are an important facet of
Alaska Native economies because they
provide viable and essential means for
families to support themselves in this
remote environment. The sharing of
subsistence resources also helps
maintain traditional family and
community organizations. In addition to
their dietary benefits, subsistence
resources provide special foods for
religious and social occasions, and
materials for personal and family use.
Subsistence hunting also links Alaska
Native communities to the larger market
economy. Many households within the
communities earn money from selling
art work from the crafting of whale
baleen and walrus ivory, and from
clothing made from fur-bearing
mammals.
The Alaska Eskimo Whaling
Commission, the North Slope Borough,
and others requested that DOI consider
marine mammals’ health as a critical
part of this proposed rule. Throughout
the rule, BOEM and BSEE have
proposed elements designed to increase
safety of oil and gas exploration in ways
that would help protect marine
mammals by reducing the likelihood
and/or severity of oil spills. The Alaska
Eskimo Whaling Commission and its
whaling captains have worked with
BOEM to help document traditional
knowledge pertaining to bowhead
whales, including movement and
behavior. Bowhead hunters are
concerned that the effects of offshore oil
and gas exploration might displace
migrating bowhead whales.
Accordingly, BSEE proposes to revise
§ 250.300(b) in order to: (i) Require
operators to capture all petroleum-based
mud and associated cuttings that result
from Arctic OCS exploratory drilling
operations to prevent their discharge
into the marine environment; and (ii)
clarify the Regional Supervisor’s
discretion to require operators to
capture water-based mud and associated
cuttings from Arctic OCS exploratory
drilling (after completion of the hole for
the conductor casing) to prevent their
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discharge into the marine environment,
based on factors such as the proximity
of exploratory drilling operations to
subsistence hunting and fishing
locations or the extent to which such
discharges might cause marine
mammals to alter their migratory
patterns in a manner that interferes with
subsistence activities or that might
otherwise adversely affect marine
mammals, fish, or their habitat(s).
Given the importance of subsistence
hunting and other activities to the
Alaska Native communities, operators
are encouraged to work directly with
interested parties to help mitigate
potential impacts to subsistence
activities. In addition, BOEM will
continue to fund and support studies to
better understand impacts from OCS
operations on marine mammals and
subsistence activities.4
The North Slope Borough also
expressed concern that oil and gas
development not overwhelm local
infrastructure, energy supplies, and
services, and that local residents be
provided the capacity—both in terms of
training and resources—to protect their
communities and important subsistence
use areas. For this reason, DOI proposes
to require operators to provide
information about their plans to
minimize the impact of their
exploratory drilling operations on
community infrastructure and their
plans to provide the communities with
oil spill cleanup training and resources.
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2. Environmental Organizations
DOI also met directly with
environmental organizations to review
and discuss recommendations for Arctic
oil and gas regulations. The PEW
Charitable Trusts requested that BSEE
revise 30 CFR 250.447 in order to
require blowout preventer (BOP)
pressure testing every 7 days for drilling
and completion operations (an increase
from every 14 days). BSEE proposes to
amend the language in § 250.447 in
order to require operators on the Arctic
OCS to pressure test the BOP system
every 7 days during exploratory drilling
operations. This proposed requirement
is also a safety measure included in
Shell’s 2012 Arctic exploratory drilling
program. Additionally, BSEE is
proposing to add a new § 250.471,
which would require that a capping
4 BOEM’s Environmental Studies Program has
made significant investments into studying
potential impacts from operations related to oil and
gas exploration. For example, BOEM has funded
bowhead whale studies incorporating Traditional
Ecological Knowledge and tagging data to learn
more about bowhead whale migration through the
Chukchi Sea in the fall and winter (Quakenbush et
al., 2010).
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stack be available and positioned to
arrive at the well within 24 hours after
a loss of well control and a cap and flow
system and that a containment dome be
available and positioned to arrive at the
well within 7 days after a loss of well
control.
The Wilderness Society requested that
BSEE consider implementing Arcticspecific provisions for OSRPs. BSEE
proposes to add several requirements for
OSRPs in this rule. In particular, BSEE
proposes to require that operators
conducting exploratory drilling on the
Arctic OCS account for how they would
increase oil encounter rates and the
effectiveness of spill response
techniques and equipment when sea ice
is present. BSEE also proposes to add
new provisions to 30 CFR part 254 for
Arctic OCS exploratory drilling
operators to, among other things,
account for enhanced oil spill response
training and exercises, as well as
address the maintenance of response
capabilities in the face of seasonal gaps
in operations.
3. Oil and Gas Operators
DOI held further meetings throughout
the summer of 2013 with individual oil
and gas companies to hear their
perspectives on possible regulations for
Arctic OCS operations. The oil and gas
operators emphasized a preference for
performance-based rules as opposed to
prescriptive rules, and also stressed the
need for early engagement with the
agencies in order to achieve up-front
regulatory consistency. While elements
of the proposed rule are prescriptive in
nature, BOEM and BSEE endeavored to
identify opportunities where
performance-based requirements were
feasible and would achieve the Bureaus’
goals. For these reasons, among others,
BOEM proposes to add a new
requirement that operators submit an
IOP for their proposed Arctic
exploratory drilling operations and
describe at an early point in the
planning process how their exploratory
drilling program would be designed and
conducted in an integrated manner
suitable for Arctic OCS Conditions. The
IOP process is intended to facilitate the
prompt sharing of information among
the relevant Federal agencies (e.g.,
BOEM, BSEE, U.S. Fish and Wildlife
Service (USFWS), U.S. Coast Guard
(USCG), National Oceanic and
Atmospheric Administration (NOAA),
U.S. Army Corps of Engineers, EPA) and
the State of Alaska. The IOP process
would also provide the relevant
agencies an early opportunity to engage
in a meaningful and constructive
dialogue with operators and each other.
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9923
The goal of the IOP and the enhanced
and early dialogue is to have a wellplanned, safe operation. Early
communication on planning is also
anticipated to minimize the potential for
project delays.
D. Expected Benefits Justifying Potential
Costs
The initial RIA for this proposed rule
estimates that it would result in
economic costs ranging from $1.1 to 1.2
billion, discounted at 7 percent and 3
percent respectively, over 10 years. The
above estimated cost range reflects the
increase in costs over the baseline costs,
as discussed elsewhere in this notice.
While many of the economic and
other benefits of the proposed rule—
based primarily on preventing or
reducing the severity or duration of
catastrophic oil spills—are difficult to
quantify, BOEM and BSEE have
determined that the benefits of the
proposed rule would justify its potential
costs and that it is appropriate to
proceed with this proposal. The
probability of a catastrophic oil spill is
very low; however, the Deepwater
Horizon oil spill demonstrated that even
such low probability events can have
devastating economic and
environmental results. As of October
2014, by its own account, BP spent over
$14 billion for cleanup and response
operations related to the Deepwater
Horizon oil spill. The benefits of the
proposed rule would accrue from a
relief rig, increased safety measures, and
other requirements that are expected to
reduce the potential for an incident
resulting in an oil spill associated with
Arctic offshore operations and, if an
incident occurs, to reduce the duration
of a spill.
The Arctic OCS and its surrounding
land and waters have a unique
significance to Alaska Natives, who rely
on them for traditional cultural
purposes and depend on them for
subsistence. Similarly, many other
Americans place a very high value on
protecting the ecosystem, including the
sensitive environment and wildlife, of
this largely frontier area. Thus,
prevention of a catastrophic oil spill,
and reduction of the duration of a spill
if one occurs, would have extremely
important, even though largely
unquantifiable, cultural and societal
benefits for the Nation.
Moreover, as explained elsewhere,
this proposed rule would help achieve
the National Arctic Strategy goals of
protecting the unique and sensitive
Arctic ecosystems, as well as the
subsistence needs, culture and
traditions of the Alaska Native
communities, while reducing reliance
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on imported oil and strengthening
National energy security. The proposed
requirements—which are specifically
tailored to the Arctic OCS—would
provide additional clarity and
specificity regarding BOEM’s and
BSEE’s expectations for safe and
responsible development of Arctic
resources and the particular actions that
lessees, owners and operators must take
in order to meet those expectations.
This additional clarity and specificity is
intended to help the oil and gas
industry to plan better and to more
effectively conduct exploratory drilling
on the Arctic OCS, resulting in the
development and production of oil and
gas with lower risk and fewer delays
than have occurred under the current
rules. According to BOEM’s 2011
Assessment of Undiscovered
Technically Recoverable Oil and Gas
Resources of the Nation’s Outer
Continental Shelf, there are
approximately 17.8 billion barrels of
economically recoverable oil and about
50.1 trillion cubic feet of economically
recoverable natural gas in the Beaufort
Sea and Chukchi Sea Planning Areas
combined. Thus, the impact of
production in the Arctic region on U.S.
energy independence and energy
security could be substantial.
III. Proposed Regulations for Arctic
OCS Exploratory Drilling
The existing OCS oil and gas
regulatory regime is extensive and
covers all offshore facilities or
operations in any OCS region, as
appropriate and applicable. BOEM and
BSEE use these regulations in their
respective oversight of OCS leasing,
exploration, development, production,
and decommissioning. Depending on
the type of activity, operators are subject
to the same regulatory requirements,
such as: application procedures and
information requirements for
exploration, development, and
production activities; pollution
prevention and control; safety
requirements for casing and cementing
and the use of a BOP and diverter
systems; design, installation, use and
maintenance of OCS platforms to ensure
structural integrity and safe and
environmentally protective operations;
decommissioning; development and
implementation of Safety and
Environmental Management Systems
(SEMS); and preparation and
submission of OSRPs (see generally 30
CFR parts 250, 254, and 550).
The existing regulations also contain
provisions that apply to specific regions
or atypical activities or operating
conditions, especially, for example,
where drilling occurs in deep water or
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in a ‘‘frontier’’ area (typically
characterized by its remote location and
limited infrastructure and operational
history, such as the Arctic OCS region).
In these cases, BOEM and BSEE have
special requirements, such as
information and design requirements for
deep-water development projects
(§§ 250.286 through 250.295); use of
appropriate equipment, third-party
audits, and contingency plans in
frontier areas or other areas subject to
subfreezing conditions (§§ 250.417(c)
and 250.418(f)); the placement of subsea
BOP systems in mudline cellars when
drilling occurs in areas subject to icescouring (§ 250.451); and emergency
plans and critical operations and
curtailment procedures information in
the Alaska OCS Region (§§ 550.220 and
550.251).
Though there is currently a
comprehensive OCS oil and gas
regulatory program, there is a need for
new and amended regulatory measures
for Arctic OCS exploratory drilling by
MODUs. These proposed regulations, in
combination with existing regulations
(which would continue to apply to
Arctic OCS operations unless otherwise
expressly stated), are intended to ensure
that exploratory drilling operations are
well planned from the outset and then
conducted safely and responsibly in
relation to the unique Arctic
environment and the local communities
that are closely connected to the region
and its resources. The key elements of
the proposed rule are:
A. Measures That Address
Recommendations—The proposed rule
addresses recommendations contained
in several recent reports on OCS oil and
gas activities (e.g., the Arctic Council,
Arctic Offshore Oil and Gas Guidelines
(2009); the National Commission on the
BP Deepwater Horizon Oil Spill and
Offshore Drilling (2011); Ocean Energy
Safety Advisory Committee
Recommendations (2013); DOI’s 60-Day
Report (2013); the Working Group’s
report entitled, ‘‘Managing for the
Future in a Rapidly Changing Arctic, A
Report to the President’’ (March 2013);
the National Arctic Strategy (May 2013);
and the Arctic Council, Arctic Offshore
Oil and Gas Guidelines: Systems Safety
Management and Safety Culture (March
2014)).
B. IOP Requirement - During
exploratory drilling operations on the
Arctic OCS, operators may face
substantial environmental challenges
and operational risks throughout every
phase of the endeavor, including
preparations, mobilization, in-theater
drilling operations, emergency response
and preparedness, and demobilization.
Thorough advanced planning is critical
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to mitigating these challenges and risks.
One of the key components of this
proposed rule is a requirement that
operators explain how their proposed
Arctic OCS exploratory drilling
operations would be fully integrated
from start to finish in a manner suitable
for Arctic OCS Conditions and that they
provide this information to DOI at an
early stage of the planning process.
This rule proposes to require that
operators develop and submit an IOP to
DOI, acting through its designee, BOEM,
at least 90 days in advance of filing their
EP. The purpose of the IOP is to
describe, at a strategic or conceptual
level, how exploratory drilling
operations will be designed, executed,
and managed as an integrated endeavor
from start to finish. The IOP is intended
to be a concept of operations that would
include a description of the various
aspects of an operator’s proposed
exploratory drilling activities and
supporting operations and how the
operator’s program would be designed
and conducted in a manner that
accounts for the challenges presented by
Arctic OCS Conditions. The primary
issues DOI would expect operators to
address relative to Arctic OCS
Conditions include, but are not limited
to:
1. Vessel and equipment design and
configurations;
2. The overall schedule of operations,
including contractor work on critical
components;
3. Mobilization and demobilization
operations and maintenance
schedule(s);
4. In-theater drilling program
objectives and timelines for each
objective;
5. Weather and ice forecasting and
management capabilities;
6. Contractor management and
oversight; and
7. Preparation and staging of spill
response assets.
DOI recognizes that other Federal
agencies have primary oversight
responsibility for some of the previously
listed activities. Upon receipt of the
IOP, DOI would engage with members
of the Working Group and promptly
distribute the IOP to the State of Alaska
and Federal government agencies
involved in the review, approval, or
oversight of various aspects of OCS
operations.
However, the IOP process would not
require agencies to review or approve
the IOP or an operator’s planned
activities. The IOP is a conceptual,
informational document designed to
ensure that an operator pays thorough
and early attention to the full suite of
regulated activities, and to give
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regulatory agencies a preview of an
operator’s approach to regulatory
compliance and integrated planning.
Thus, the IOP would enable relevant
agencies to familiarize themselves, early
in the planning process, with the
operator’s overall proposed program
from start to finish. This, in turn, would
allow DOI and those agencies to
coordinate and provide early input to
the operator regarding potential issues
presented by the proposed activities
with respect to any future plan
approvals and permitting requirements,
including aspects of the program that
might require additional details or
refinement. The proposed IOP
requirement—and the proposed rule in
general—would not, however, interfere
with or supplant operators’ obligations
to comply with all other applicable
Federal agency requirements. Each
agency that receives an IOP would
continue to review the relevant details
of an operator’s planned activities for
compliance with that agency’s
regulatory requirements in the
appropriate manner and at the
appropriate time under its own
regulatory program.
C. SCCE and Relief Rig Capabilities—
In Arctic OCS exploratory drilling, there
is a need for operators to demonstrate
that they would have access to, and
could deploy, well control and
containment resources that would be
adequate to promptly respond to a loss
of well control. This equipment is
already readily available and accessible
in the Gulf of Mexico due to the level
of activity in that area. Ensuring that
operators have all necessary
redundancies in place is critical, as
there is no guarantee that a single
measure could control or contain a
worst-case discharge (WCD). Therefore,
BSEE proposes to require operators who
use a MODU for Arctic OCS exploratory
drilling to have access to, and the ability
to deploy, SCCE (e.g., a capping stack,
cap and flow system, and containment
dome) within the timeframes discussed
elsewhere in this proposed rule and that
the SCCE be capable of functioning in
Arctic OCS Conditions. BSEE also
proposes that operators have access to a
separate relief rig that would be staged
at a location such that it could arrive on
site and be capable of drilling a relief
well under anticipated Arctic OCS
Conditions within specified timeframes.
This equipment is fundamental to safe
and responsible operations on the Arctic
OCS, where existing infrastructure is
sparse, the geography and logistics make
bringing equipment and resources into
the region challenging, and the time
available to mount response operations
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is limited by changing weather and ice
conditions, particularly at the end of the
drilling season. Operators may request
approval of alternative compliance
measures under existing regulations, if
they can demonstrate that such
alternative equipment or procedures
could provide a level of safety and
environmental protection equal to or
surpassing the protection provided by
the proposed SCCE and relief rig
requirements (30 CFR 250.141). This
provision enables operators to request
approval for innovative technological
advancements that may provide them
additional flexibility, provided that the
operator can establish that such
technology provides at least the same
level of protection as the proposed
requirements.
D. Planning for the Variability and
Challenges of the Arctic OCS
Conditions—Reliable weather and ice
forecasting play a significant role in
ensuring safe operations on the Arctic
OCS. Advanced forecasting and tracking
technology, information sharing among
industry and government, and local
knowledge of the operating environment
are essential to managing the substantial
challenges and risks that Arctic OCS
Conditions pose for all offshore
operations. In light of the threats posed
by ice and extreme weather events,
BOEM and BSEE propose to require that
operators include in their IOPs, EPs, and
APDs, at appropriate levels of
specificity for each document, a
description of their weather and ice
forecasting capabilities for all phases of
their exploration program and their alert
procedures and thresholds for activating
ice and weather management systems.
Once operations commence, operators
would also be required to:
1. Notify BSEE immediately of any sea
ice movement or condition that has the
potential to affect operations or trigger
ice management activities; and
2. Notify BSEE of the start and
termination of ice management
activities and submit written reports
after completing such activities.
E. Arctic OCS Oil Spill Response
Preparedness—Operators need to be
prepared for a quick and effective
response in the event of an oil spill on
the Arctic OCS and be ready to
coordinate activities with the Federal
government and other stakeholders. The
OSRPs and related activities should be
tailored to the unique Arctic OCS
operating environment to ensure that
operators have the necessary equipment,
training, and personnel for the Arctic
OCS. Among other things, this
rulemaking would establish specific
planning requirements to maximize the
application of oil spill response
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9925
technology and ensure a coordinated
response system that is designed to
address the challenges inherent to the
Arctic region.
F. Reducing Pollution from Arctic
OCS Exploratory Drilling Operations—
Partners, primarily Alaska Natives, and
stakeholders have expressed concern
that mud and cuttings from exploratory
drilling could adversely affect marine
species (e.g., whales and fish) and their
habitat and compromise the
effectiveness of subsistence hunting
activities. Existing environmental
analyses support these concerns and
also demonstrate that such discharges
could affect water quality, benthic
habitat, and marine organisms within
the localized area (see, e.g., Shell Gulf
of Mexico, Inc.’s Revised Chukchi Sea
Exploration Plan, Burger Prospect
Environmental Assessment (2011)).
BSEE proposes to require the capture of
all petroleum-based mud and associated
cuttings from Arctic OCS exploratory
drilling operations to prevent their
discharge into the marine environment.
The new provision would also clarify
the Regional Supervisor’s discretionary
authority to require that operators
capture all water-based mud and
associated cuttings from Arctic OCS
exploratory drilling operations (after
completion of the hole for the conductor
casing) to prevent their discharge into
the marine environment. This discretion
would be exercised based on various
factors such as the proximity of
exploratory drilling operations to
subsistence hunting and fishing
locations or the extent to which such
discharges might cause marine
mammals to alter their migratory
patterns in a manner that interferes with
subsistence activities or might adversely
affect marine mammals, fish, or their
habitat(s).
G. Oversight, Management, and
Accountability of Operations and
Contractor Support—An effective risk
management framework at the
beginning of a project incorporates
many components, including planning,
vessel design, contractor selection, and
an assessment of regulatory
requirements for all facets of the project.
DOI proposes to require that operators
provide an explanation, at a conceptual
level, of how they would apply their
oversight and risk management
protocols to both personnel and
contractors to support safe and
responsible exploratory drilling on the
Arctic OCS. It should be noted that
these proposed regulations, and DOI’s
existing regulations concerning OCS oil
and gas operations, would require
varying levels of information about
operator safety and oversight
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management at progressive stages of the
planning and approval process. This
would start with the most general
information and narrow down to
increasing levels of detail with
successive regulatory submittals, as the
project would proceed from planning to
implementation.
In addition, the proposed rule would
require Arctic OCS operators to:
1. Report threatening sea ice
conditions and ice management
activities, and unexpected operational
issues that could result in a loss of well
control;
2. Increase their BOP pressure testing
frequency;
3. Conduct real-time monitoring of
various aspects of well operations, e.g.,
the BOP control system;
4. Increase their SEMS auditing
frequency; and
5. Enhance their oil spill
preparedness and response capabilities
for Arctic OCS operations.
A summary of the major provisions of
this rulemaking follows.
IV. Section-By-Section Discussion
This portion of the preamble provides
an explanation of the specific regulatory
changes proposed in this rule and why
they are necessary. At the outset, this
discussion addresses the proposed
definitions of the terms Arctic OCS and
Arctic OCS Conditions for use in both
BOEM’s and BSEE’s regulations in order
to provide context for the rest of the
proposed provisions. Since this is a
joint BOEM and BSEE proposed rule,
the remainder of the Section-by-Section
discussion is organized according to
how operators would seek to comply
with the proposed regulations, rather
than the order in which they would
appear in the Code of Federal
Regulations. After introducing the
definitions of Arctic OCS (for purposes
of proposed §§ 250.105, 254.6, and
550.105) and Arctic OCS Conditions (for
purposes of proposed §§ 250.105 and
550.105), the Section-by-Section
discussion provides an explanation of
the remainder of BOEM’s proposed
regulations (i.e., proposed §§ 550.105,
550.200, 550.204, 550.206, and
550.220), and then follows with the
remainder of BSEE’s proposed
regulations (i.e., proposed §§ 250.105,
250.188, 250.198, 250.300, 250.402,
250.418, 250.447, 250.452, 250.470,
250.471, 250.472, 250.473, and
250.1920; proposed §§ 254.6, 254.55,
254.65, 254.70, 254.80, and 254.90).
Although BSEE permitting and
operational requirements appear earlier
in Title 30 of the CFR at Part 250, with
the BOEM requirements following in 30
CFR part 550, in practice the IOP and EP
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phases governed by the 30 CFR part 550
regulations would precede the drilling
approval and oversight phases governed
by 30 CFR part 250 (operations).
Requirements to prepare for an oil spill,
which are contained in 30 CFR part 254,
may be met at any time before handling,
storing, or transporting oil in operations
BSEE permits under Part 250. Finally,
the Section-by-Section discussion
includes a process flowchart of BOEM’s
and BSEE’s current regulatory
framework for Arctic OCS exploratory
drilling and how the proposed
requirements would be integrated into
that framework.
A. Definitions (§§ 250.105, 254.6, and
550.105)
Arctic OCS
For the purposes of this proposed
rulemaking, Arctic OCS is defined as the
Beaufort Sea and Chukchi Sea Planning
Areas, as described in the Proposed
Final OCS Oil and Gas Leasing Program
for 2012–2017 (June 2012), available at
www.boem.gov/uploadedFiles/BOEM/
Oil_and_Gas_Energy_Program/Leasing/
Five_Year_Program/2012–2017_Five_
Year_Program/PFP%2012–17.pdf (see
pp.21–24). This definition would appear
in §§ 250.105, 254.6, and 550.105. As
described previously, BOEM and BSEE
have determined that these areas are
both the subject of current exploration
and development interest and subject to
conditions that present significant
challenges to such operations.
Arctic OCS Conditions
Sections 250.105 and 550.105 would
be revised to add a definition for Arctic
OCS Conditions. The definition is
necessary because these proposed
regulations are designed largely around
the particular challenges presented by
Arctic OCS Conditions. The term Arctic
OCS Conditions would be defined to
describe both the environmental
conditions and functional
characteristics (e.g., geographic
remoteness, limited infrastructure,
subsistence hunting areas) that oil and
gas operators can reasonably expect to
encounter during exploratory drilling
operations and when responding to a
loss of well control on the Arctic OCS.
Depending on the time of year, relevant
environmental conditions and the
proposed definition include, but are not
limited to, the following: ‘‘extreme cold,
freezing spray, snow, extended periods
of low light, strong winds, dense fog, sea
ice, strong currents, and dangerous sea
states.’’ This definition would not affect
or alter any other existing Federal
regulatory requirements.
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It is crucial for OCS oil and gas
operators to have a clear understanding
of the conditions they would likely
encounter during exploratory drilling
operations and when responding to a
loss of well control on the Arctic OCS.
Offshore oil and gas exploration
involves inherent risks to human safety
and the environment. If not effectively
addressed, Arctic OCS Conditions could
multiply these risks. Thus, the proposed
definition also recognizes that ‘‘the
Arctic’s remote location, limited
infrastructure, and existence of
subsistence hunting and fishing areas
are also characteristic of the Arctic
region’’ and must be considered to
ensure safe operations and minimize
impacts to the environment and to other
users of the area. Addressing these
factors would enable industry to
proactively safeguard people, facilities,
equipment, and the environment.
B. Additional Regulations Proposed by
BOEM
Definitions (§ 550.200)
The acronym ‘‘IOP’’—meaning
Integrated Operations Plan—would be
inserted into the proper alphabetical
location within existing § 550.200, for
purposes of the IOP provisions at
proposed § 550.204, as discussed next.
When must I submit my IOP for
proposed Arctic exploratory drilling
operations and what must the IOP
include? (§ 550.204)
This proposed rule would require the
operator to develop an IOP for each
proposed exploratory drilling program
on the Arctic OCS, and to submit the
IOP to DOI, through its designee, BOEM,
at least 90 days in advance of filing its
EP. The IOP would need to describe
how the proposed exploratory drilling
program would be designed and
conducted in an integrated manner
suitable for Arctic OCS Conditions and
would address each of the information
requirements identified in proposed
§ 550.204. Operators may also choose to
address the requirements in §§ 550.211
through 550.228, which could facilitate
the later formal review of the operator’s
EP. The IOP should be detailed enough
to allow DOI, other relevant Federal
agencies, and the State of Alaska to:
1. Familiarize themselves with the
proposed operations as an integrated
project from start to finish; and
2. Provide constructive feedback to
the operator concerning the conceptual
plans reflected in its IOP.
DOI recognizes that when the IOP is
submitted, operators might not possess
all the detailed and specific information
that may be more readily available later
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in the planning process; e.g., contracts
for vessels may not be finalized, precise
dates of drilling may be uncertain, or
the exact staging location of assets, such
as the relief rig or SCCE, may be
unknown. For BOEM’s and BSEE’s
purposes, operators would submit more
detailed information through the EPs
and APDs, as appropriate.
Though BOEM would review the IOP
to ensure that the operator’s submission
addresses each of the elements listed in
§ 550.204, the IOP would not require
approval by DOI or the other relevant
agencies. Instead, the IOP would be an
informational document intended to
facilitate early review of important
concepts related to an operator’s
proposed exploratory drilling program.
This review would assist DOI and other
relevant agencies in developing an
understanding of, and familiarity with,
the operator’s overall proposed
exploratory drilling program early in the
planning process.
DOI recognizes that the information
requirements of § 550.204 could
implicate other Federal agencies’ and
the State of Alaska’s statutory and
regulatory mandates. For example, the
USCG administers laws and regulations
governing maritime safety, security, and
environmental protection and is also
responsible for inspecting the vessels to
which those laws and regulations apply.
In acknowledging the USCG’s principal
jurisdiction over vessel safety and
security, DOI has determined that
information, early in the process,
pertaining to the safety of operations,
vessel mobilization, demobilization, and
tow plans, is also essential to DOI’s
statutory and regulatory responsibilities
related to Arctic OCS oil and gas
activities. The IOP process is intended
to facilitate the sharing of information
among the relevant Federal agencies and
the State of Alaska and to provide the
relevant agencies an early opportunity
to engage in a meaningful and
constructive dialogue with operators,
consistent with the policies articulated
in E.O. 13580 (Interagency Working
Group on Coordination of Domestic
Energy Development and Permitting in
Alaska, discussed earlier).
Upon receipt, DOI would engage
fellow members of the Working Group
and distribute the IOP to other Federal
government agencies involved in the
review, approval, or oversight of aspects
of OCS operations (e.g., BOEM, BSEE,
USFWS, USCG, NOAA, and EPA), as
well as the State of Alaska. Early
engagement by these entities would
allow them to become familiar with the
operator’s overall proposed exploratory
drilling program and could provide a
meaningful opportunity to offer early
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feedback to the operator concerning its
proposed activities and any identifiable
issues that might affect future
permitting decisions. DOI would also
encourage the assembly of an
interagency coordination team to
facilitate and coordinate agency review
and feedback. Any feedback could be
provided individually by the relevant
Federal agencies or the State of Alaska,
or collectively through DOI.
BOEM also plans to promptly post
each IOP on its Web site. BOEM would
not solicit public input on the IOP;
instead, the IOP would be informational
only, affording the public an early
opportunity to view key concepts of a
proposed exploratory program. This
effort responds to stakeholder concerns
that BOEM does not provide the public
with sufficient time to participate
meaningfully in BOEM’s administrative
process for proposed exploratory
drilling activities on the Arctic OCS.
Typically, the public first becomes
aware of an operator’s plans for
exploratory drilling when the operator
submits its EP. BOEM acknowledges
that public review periods for EPs are
relatively short in duration. However,
this is a result of the OCSLA provision
that requires BOEM to approve,
disapprove, or require modifications to
an EP within 30 days of BOEM deeming
the EP submitted (43 U.S.C. 1340(c)(1)),
thus placing modification of the length
of the review period outside the
discretion or authority of the agency
absent Congressional action. An early
opportunity to view the IOP and the key
concepts of the proposed exploratory
drilling program, however, will enhance
existing public engagement
opportunities.
Paragraph (a), Vessels and Equipment
Operators must plan to adapt their
exploratory drilling operations to Arctic
OCS Conditions. Although generally the
equipment for extracting oil and gas
from the OCS is the same for the
offshore Arctic as anywhere else on the
OCS, the equipment might need to be
modified, procedures might need to be
adjusted, or personnel might need to be
specifically trained for work conditions
on the Arctic OCS. For example, cranes
might need to be modified for
operations under ice loading that could
be anticipated during Arctic OCS
operations, and be de-rated to account
for reduced strength in extreme cold
temperatures. Accordingly, this
provision would require that operators
submit, ‘‘[i]nformation describing how
all vessels and equipment will be
designed, built, and/or modified to
account for Arctic OCS Conditions’’ and
is designed to ensure that the operator
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9927
is planning to deploy vessels and
equipment capable of operating safely
on the Arctic OCS. Operators would
need to submit information sufficient to
allow DOI and other relevant agencies
(e.g., the USCG) to understand the
function of each vessel within the
proposed fleet of vessels and how the
vessels would be capable of performing
their identified roles in the proposed
exploratory drilling program safely and
effectively.
Paragraph (b), Exploratory Drilling
Program Schedule
The proposed rule would require the
IOP to include an exploratory drilling
program schedule of operations
including importantly, contractor work
on critical components of the program
(e.g., inspection and testing of critical
equipment such as BOPs or SCCE).
Thorough advanced planning regarding
the proposed schedule for operations is
an important component of the IOP,
particularly in light of the limits that
returning sea ice can place on the
drilling season on the Arctic OCS, and
for elements of operations for which
operators are relying upon outside
contractor deliverables. Furthermore, it
is important for BOEM and other
relevant agencies to have information
regarding how the timing of proposed
operations aligns with expected
seasonal ice encroachment, as well as
how the timing of proposed operations
may interact with seasonal marine
mammal migrations and subsistence
activities, for purposes of understanding
the potential environmental impacts.
This will help BOEM and other relevant
agencies develop an understanding of
how the operator proposes to conduct
operations safely.
The proposed schedule would need to
include, for example, when an operator
intends to enter waters overlying the
Alaska OCS (including transit time to
the proposed drilling site), when
drilling is expected to commence and
conclude, dates of operations, and when
the operator plans to leave the vicinity
of drilling operations. The schedule
would also need to include the critical
dates for completion or activation of
components under construction, repair,
or storage by outside contractors. This
provision would help assure DOI and
other relevant agencies that the operator
and its contractors have developed a
reasonable schedule for executing each
phase of the exploration program and
are capable of conducting exploratory
drilling activities safely in Arctic OCS
Conditions.
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Paragraph (c), Mobilization and
Demobilization
This provision would require
operators to include in their IOP a
description of their mobilization and
demobilization operations, including
tow plans suitable for Arctic OCS
Conditions, as well as their general
maintenance schedules for vessels and
equipment. This element is designed to
help DOI and other relevant agencies
understand the extent to which
operators:
1. Have accounted for the conditions
likely to be encountered on the Arctic
OCS; and
2. Are prepared to handle the
substantial environmental challenges
and associated operational risks present
throughout the mobilization and
demobilization of personnel and
equipment.
The requested information would
facilitate coordination between DOI and
the USCG. Similarly, having
information about where vessels would
come from and go to before and after
entering the waters overlying the Alaska
OCS would aid, for example, DOI’s and
other relevant agencies’ early
understanding of potential
environmental issues, such as aquatic
invasive species that might be carried
on vessels.
This provision would also require
consideration of how repairs to, and
maintenance of, vessels and equipment
might affect the larger exploratory
drilling program. This information
could facilitate DOI’s and other relevant
agencies’ understanding of potential
environmental considerations and safety
aspects of the projected operational
schedules.
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Paragraph (d), Exploratory Drilling
Program Objectives, Timelines, and
Contingency Plans
This provision would require
operators to include in their IOP a
description of their ‘‘exploratory drilling
program objectives and timelines for
each objective, including general plans
for abandonment of the well(s)’’ under
a variety of circumstances. This
description would help DOI and other
relevant agencies familiarize themselves
with the operator’s plans for a welldesigned, safe operation with clear
objectives for employees and contractors
that would allow ample flexibility in
light of the difficult and variable
conditions on the Arctic OCS.
A fully developed exploration
program includes, among other things:
the operator’s general plan of how many
wells it plans to drill in a particular
season; the timing and sequence of
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those operations; locations of the wells;
necessary equipment and resources,
including information on support
vessels; and the operator’s contingency
plans in the event that temporary
abandonment would become necessary.
To the extent that relevant information
submitted with the IOP has not
changed, the operator could later
incorporate that information into its EP.
Thorough advanced planning of the
operator’s objectives, as well as clear
timelines for the accomplishment of
each objective, are essential, particularly
in light of the limited seasonal drilling
window on the Arctic OCS.
Given the uncertainties created by the
challenging Arctic OCS Conditions, it is
equally essential for an operator to
acknowledge and plan for contingencies
and delays that might arise. For
example, an operator would need to
provide general information regarding
how it would safely respond to
unanticipated ice encroachment at the
drill site, including safe and secure
temporary abandonment of the well and
relocation of the drilling rig, as
necessary. DOI would need to be
provided with information that explains
how the operator has considered these
elements of its exploration program,
well in advance of operations. Also, if
an operator plans to drill multiple wells,
DOI must be provided with information
regarding the anticipated objectives and
timelines for each well. Similarly, an
operator would be expected to indicate
whether it intends to abandon the
well(s) at the end of the season and, if
the operator intends to abandon the
well, whether such abandonment would
be temporary or permanent.
Paragraph (e), Weather and Ice
Forecasting and Management
One of the key drivers of this
proposed rule is DOI’s need to
understand how operators would
account for the variable conditions on
the Arctic OCS and how those
conditions might affect drilling
activities. One important component of
an operator’s overall program is
accounting for adverse weather and ice
conditions and developing a plan to
respond to those conditions.
Consequently, this provision would
require operators to describe their
weather and ice forecasting capabilities
for all phases of the exploration
program, including a description of how
they would respond to and manage ice
hazards and weather events. The
challenges presented by Arctic OCS
Conditions are not limited to the period
of active drilling operations, but would
create difficulties throughout all phases
of an exploratory drilling program,
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including mobilization and
demobilization. Accordingly, it is
important for DOI and other relevant
agencies to understand the operator’s
plans for implementing ice and weather
forecasting and management systems
that would be operational around the
clock from start to finish.
Paragraph (f), Contractors
This provision would require
operators to provide in their IOP a
description of work to be performed by
contractors supporting their exploratory
drilling program (including
mobilization and demobilization), how
such work would be designed or
modified to account for Arctic OCS
Conditions, and operators’ strategy for
contractor management, oversight, and
risk management. This information is
designed to help DOI and other relevant
agencies understand the operator’s
strategies for developing, early in the
planning process, a rigorous and
effective operational management and
oversight system for its contractors that
is specifically tailored for operations on
the Arctic OCS. Information regarding
the nature and timeline of operational
elements for which the operator would
rely on contractors would aid in a full
understanding of the various inputs and
contingencies that might affect the
planned execution of the proposed
operations.
The IOP would need to describe, for
example, what types of operations the
operator would contract out and how
the operator would oversee the
contractor to ensure the contractor’s
work product would be suitable for
Arctic OCS operations. At the IOP stage,
the specific names of contractors would
not be necessary but could be provided,
if known. The focus of this proposed
requirement is to facilitate DOI’s and
other relevant agencies’ understanding
of how the operator plans to rely on
contractors and how it plans to manage
its contractor relationships in order to
ensure safe and responsible drilling
operations.
Paragraph (g), Safety
BOEM proposes to require that
operators include in their IOP a
description of how they ‘‘will ensure
operational safety while working in
Arctic OCS Conditions,’’ including but
not limited to, the safety principles
applicable to operators and their
contractors, the accountability structure
within operators’ organizations for
implementing these principles, how
operators would communicate these
principles to their employees and
contractors, and how operators would
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determine successful implementation of
these principles.
The OCSLA provides that all
operations taking place on the OCS
‘‘should be conducted in a safe manner
by well-trained personnel using
technology, precautions, and techniques
sufficient to prevent or minimize the
likelihood of blowouts, loss of well
control, fires, spillages, physical
obstruction to other users of the waters
or subsoil and seabed, or other
occurrences which may cause damage to
the environment or to property, or
endanger life or health’’ (43 U.S.C.
1332(6)). Also, operators are required to
demonstrate through their EPs and
APDs that they have planned and are
prepared to conduct activities in a
manner that conforms to the OCSLA
and applicable implementing
regulations, and that their activities will
be conducted safely (see 43 U.S.C.
1340(c)(1); 30 CFR 250.106, 250.107,
550.202 paragraphs (a) and (b)). The
proposed safety information
requirement would help DOI and other
relevant agencies (e.g., USCG)
familiarize themselves with the
operator’s early consideration of how its
proposed exploratory drilling program
would proceed in a safe manner with
appropriate caution and respect for the
extreme and unpredictable conditions
found offshore in the Arctic and would
be consistent with DOI’s and other
relevant agencies’ safety requirements.
This proposed safety information
element is also intended to complement
BSEE’s SEMS program by requiring
operators to identify and assess, early in
the planning stages of their proposed
exploratory drilling program, their
guiding principles for safe Arctic OCS
operations, and optimal strategies for
implementing those principles
throughout their workforce.
Proposed 30 CFR 550.204(g) would
not require an operator to provide the
same level of detail, if not available,
concerning safety of operations as
would be available at the time of the EP
and APD, or to duplicate the detail
provided in its USCG Safety
Management System program or its
BSEE SEMS program. Instead, the IOP
would need to provide a general
understanding of the principles that
operators would follow to manage risks
to ensure safety of all exploratory
drilling activities and personnel vis-àvis the conditions likely to be
encountered on the Arctic OCS. For
example, it is reasonably expected that
operators would experience freezing
spray, extended periods of low light,
strong winds, and dense fog during
operations. Operators would need to
provide a general description of how
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they would account for these
conditions, and any guiding principles
they would follow to minimize risk to
operations, personnel, vessels, and other
equipment.
Paragraph (h), Staging of Oil Spill
Response Assets
BOEM proposes to require that
operators include in their IOP
information regarding their
‘‘preparations and plans for staging of
oil spill response assets.’’ This provision
would facilitate DOI’s, and other
relevant agencies’ (e.g., USCG), early
understanding of the potential effects on
local communities from staging spill
response assets near coastal
communities, the safety and
environmental implications of plans for
mobilization and demobilization of
related vessels and equipment, the
potential environmental impacts of the
vessels staged in the area for response,
and anticipated response times based on
where the equipment will be located.
This information would be especially
relevant to the USCG, which is the
Federal On Scene Coordinator
responsible for developing the North
Slope Sub-Area Contingency Plan for
Oil and Hazardous Substances
Discharges/Releases. The USCG and all
appropriate governmental entities at the
State and local levels would have an
early understanding of the proposed
activities.
Paragraph (i), Impact of Exploratory
Drilling on Local Community
Infrastructure
BOEM proposes to require that
operators include in their IOP, a
description of their ‘‘efforts to minimize
impacts of [their] exploratory drilling
operations on local community
infrastructure, including but not limited
to housing, energy supplies, and
services.’’ This provision would
facilitate DOI’s and other relevant
agencies’ early understanding of the
potential socioeconomic implications of
the proposed exploratory drilling
program, including the extent to which
the proposed activities might strain the
limited infrastructure of coastal
communities in the Arctic, or reduce the
availability of housing, energy, food,
and health care to local communities
through increased demand and higher
costs caused by the presence of persons
supporting the exploratory drilling
program.
Paragraph (j), Local Community
Workforce and Response Capacity
BOEM proposes to require that
operators include in their IOP ‘‘[a]
description of whether and to what
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extent your project will rely on local
community workforce and spill cleanup
response capacity.’’ This provision
would encourage operators to engage in
early planning toward providing local
communities, which would incur the
greatest risk of offshore exploration
activities, with the capacity—both in
terms of training and resources—to
protect their communities and
important subsistence use areas. It is
intended to provide DOI and other
relevant agencies with early insight into
whether the proposed operations are
being planned safely, with appropriate
environmental safeguards and respect
for the other users of area resources.
This provision would also allow DOI to
develop an early understanding of
industry’s efforts to promote local
communities’ ability to participate in
and obtain benefit from future Arctic
OCS oil and gas development.
How do I submit the IOP, EP, DPP, or
DOCD? (§ 550.206)
DOI recognizes that operators may
consider some of the information
required by proposed § 550.204 to be
proprietary or commercial in nature.
Pursuant to the proposed revisions to
§ 550.206, operators would be able to
request the nondisclosure of this
information using established DOI
processes. As is currently the case with
EPs, Development and Production Plans
(DPPs), and Development Operations
Coordination Documents (DOCDs),
operators requesting the nondisclosure
of portions of an IOP should provide
BOEM with two separate versions of the
IOP; a public version from which
potentially exempt information is
redacted, and a BOEM version with
such information present, but clearly
marked as proprietary.
If I propose activities in the Alaska OCS
Region, what planning information must
accompany the EP? (§ 550.220)
As described previously, drilling
operations, especially on the Arctic
OCS, can be complex, and operators
may face substantial environmental
challenges and operational risks
throughout every phase of the endeavor.
One of the main goals of this rulemaking
is to ensure, through thorough advanced
planning, that operators are capable of
operating safely in the extreme and
challenging Arctic OCS Conditions.
BOEM first proposes to amend the
existing ‘‘Emergency Plans’’ provision at
§ 550.220(a) to add fire, explosion, and
personnel evacuation to the events for
which emergency plans are required,
and to replace the terms ‘‘blowout’’ with
‘‘loss of well control’’ and ‘‘craft’’ with
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‘‘vessel, offshore vehicle, or aircraft’’ for
clarification purposes.
BOEM next proposes to create a new
§ 550.220(c), which would set forth
additional information requirements for
EPs that are proposing exploration
activities on the Arctic OCS. BOEM
proposes to add a new performancebased provision at § 550.220(c)(1) that
would require an operator to describe
how its proposed activities would be
designed and conducted in a manner
suitable for Arctic OCS Conditions and
how these activities would be managed
and overseen as an integrated endeavor.
This description may be summarized
from the operator’s IOP or, if
appropriate, updated with any
information not available at the time of
the IOP.
BOEM also proposes to add
§ 550.220(c)(2), which would require
operators to include, as part of their EP
submissions, more detailed and updated
information concerning their weather
and ice forecasting and management
plans for all phases of their exploratory
drilling activities, including: a
description of how they would respond
to and manage ice hazards and weather
events; their ice and weather alert
procedures; their procedures and
thresholds for activating their ice and
weather management systems; and
confirmation that their ice and weather
management and alert systems would be
operated continuously throughout the
planned operations. As described
previously, DOI needs to be certain that
adequate forecasting equipment and
procedures are in place to predict and
follow developing weather and ice
conditions that might pose a risk to
operations. Also, it is essential that
operators develop and describe their
pre-established thresholds for triggering
varying levels of responsive actions in
the face of weather and ice threats, as
well as the procedures and equipment
necessary to respond to these hazards.
Furthermore, operators need to
demonstrate that they would be capable
of responding to and managing these
conditions to prevent or minimize the
risks associated with ice and adverse
weather.
BOEM next proposes to require
preliminary information concerning
SCCE capabilities, deployment of a
relief well rig, and sharing of SCCE and
spill response and cleanup assets. The
proposed informational requirements
concerning SCCE and relief well rigs
relate to the operator’s preliminary
plans for complying with BSEE’s
proposed regulations at 30 CFR 250.471
and 250.472, which will be described
later.
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Requiring information about how an
operator intends to satisfy the proposed
BSEE regulations at proposed 30 CFR
250.471 and 250.472 would allow
consideration of these issues at an early
planning stage, and would further
inform BOEM’s review of proposed EPs
under § 550.202, and other applicable
laws. It would likewise reduce the risk
of discrepancy between reviews and
approvals conducted at the EP stage and
an operator’s later-submitted APD.
While BOEM anticipates that elements
of the SCCE description required by
proposed § 550.220(c)(3) and the relief
well rig description required by
proposed § 550.220(c)(4) may be general
at the EP stage, they must be detailed
enough for BOEM to confirm that the
operator would have plans in place for
how it would conduct its operations
safely, in conformance with applicable
regulations. The description would also
need to be detailed enough to enable
BOEM to evaluate the potential
environmental implications of proposed
SCCE and relief well rig staging and
operations. Proposed § 550.220(c)(4)
would set forth some of the information
expected to be available about the relief
well rig when the EP is submitted.
The proposed § 550.220(c)(5)
provision would add an informational
requirement concerning any agreements
the operator might have with third
parties for the sharing of assets (e.g.,
SCCE, relief rigs, and oil spill response
resources) and/or any agreements to
assist each other in response and
cleanup efforts in the event of a loss of
well control or other emergency. A
cooperative, consortium-based model
should offer:
1. Logistical, operational, and
commercial efficiencies;
2. Less duplication of personnel and
equipment;
3. Reduced monetary cost of
exploration;
4. Reduced environmental footprint;
5. Reduced social costs and
interference with other users of the
OCS; and
6. A coordinated response and
cleanup effort in the event of a loss of
well control.
BOEM’s environmental impact
analyses have repeatedly shown that the
presence of vessels, aircraft, and other
equipment within the Arctic region
could result in adverse impacts to
subsistence activities and to
environmental resources (e.g., noise
impacts on marine mammals, increased
risk of bird or marine mammal
collisions, increased risk of fuel spills,
and increased air emissions). The
potential effects would be compounded
if multiple operators—each fielding its
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own fleet of drilling, resupply, and
emergency response vessels—were to
engage in activities simultaneously.
Avoiding duplication of relief well rigs,
oil spill response assets, and other
emergency response vessels and
equipment would be an effective means
to minimize environmental and social
impacts.
BOEM and BSEE strongly encourage
operators proposing exploratory drilling
activities on the Arctic OCS to enter into
mutual aid agreements for the sharing of
vessels, relief well rigs, and other assets
or services associated with responding
to an oil spill or other emergency.
Notice of these arrangements would
inform BOEM’s and BSEE’s safety and
environmental review of proposed
activities to ensure operators are fully
prepared to respond to a loss of well
control. Also, BOEM and BSEE expect
that operators, when planning a
response to a loss of well control, would
ensure that an effective and immediate
removal, mitigation, or prevention of a
discharge could be achieved, to the
greatest extent practicable, using private
sector capability.
Finally, proposed § 550.220(c)(6)
would add an informational
requirement concerning the conclusion
of on-site operations at the end of the
season. An operator would include a
projected date, and information used to
determine the date, when on-site
operations would be completed based
on ice conditions that will likely exist
in the relevant operational area (using
current Federal ice and weather
forecasts or other reliable forecasting
systems). An operator would also
provide a projected date, and supporting
information, on when the operator
would stop drilling operations into
zones capable of flowing liquid
hydrocarbons to the surface. That date
would need to be consistent with the
relief rig planning requirements under
proposed 30 CFR 250.472 and with the
estimated timeframe for deployment of
a relief rig under proposed
§ 550.220(c)(4).
There is no single, definitive ‘‘end of
drilling season’’ in the Arctic OCS. The
projected end-of-season dates in any
specific EP should be based on a variety
of factors, including the operator’s
equipment, procedures, and capability
to effective ly manage and mitigate risk
that are reasonably likely to occur.
Other factors include, but are not
limited to, the prevailing meteorologic
and oceanic conditions, which vary
from year to year, and the location of
proposed drilling. For example, in a
year when the encroachment of sea ice
is projected to occur later, an operator
may be able to justify a later end of
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season and avoid the need to cease
drilling operations earlier than
necessary. By contrast, in a year when
the onset of sea ice is projected to occur
earlier, the operator would need to plan
to conclude on-site operations earlier.
In projecting when to conclude onsite operations, BOEM and BSEE expect
operators to be flexible and fully
responsive to the latest ice and weather
forecasts and the best available
information for ensuring optimal timing
for the end of on-site operations. Of
course, after an EP is approved, an
operator may request approval to revise
its EP if available information regarding
its operations and anticipated
meteorologic and oceanic conditions
change.
For example, BOEM’s approval for
Shell’s 2012 Arctic operations required
drilling operations in zones where
measurable quantities of liquid
hydrocarbons were capable of flowing
into the well to be concluded 38 days
prior to November 1, based on satellite
imagery showing the five-year historical
average of earliest sea ice encroachment
over Shell’s drill site and estimates of
the time needed to drill a relief well.
The purpose of this drilling hiatus was
to reduce project risk by assuring a
greater opportunity for response and
cleanup in the unlikely event of a late
season oil spill.
BOEM and BSEE invite comments on
what kinds of Arctic weather and ice
forecasting options are currently (or
expected to be) available for use by
operators. In addition, comments may
address other factors that should be
considered in determining when on-site
operations are expected to be
completed, or when drilling into certain
hydrocarbon zones should cease each
year, given an operator’s response and
cleanup capabilities.
C. Additional Regulations Proposed by
BSEE
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Authority
The authority citation for 30 CFR part
250 would be amended to add reference
to 33 U.S.C. 1321(j)(1)(C). This statutory
provision, in addition to section 5 of the
OCSLA (43 U.S.C. 1334), provides
authority to DOI for the portions of the
proposed revisions to § 250.300 related
to preventing discharge of petroleumbased mud and cuttings from operations
that use petroleum-based mud. For
further explanation of those provisions,
see the discussion under that section.
Definitions (§ 250.105)
This section would be revised to add
definitions for Arctic OCS, Arctic OCS
Conditions, Cap and Flow System,
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Capping Stack, Containment Dome, and
Source Control and Containment
Equipment. For an explanation of the
definitions of Arctic OCS and Arctic
OCS Conditions, see the discussion of
definitions at the beginning of the
Section-by-Section analysis. The
remaining definitions are necessary
because these proposed regulations
would require the defined systems and
equipment under identified
circumstances. In addition, the
definition of District Manager would be
revised for activities on the Alaska OCS
such that District Manager would mean
Regional Supervisor, because the
Regional Supervisor in BSEE’s Alaska
OCS region performs the District
Manager’s duties.
Cap and Flow System—this term
would be defined to mean an integrated
suite of equipment and vessels,
including a capping stack and
associated flow lines, that, when
installed or positioned, is used to
control the flow of fluids escaping from
the well by conveying the fluids to the
surface to a vessel or facility equipped
to process the flow of oil, gas, and
water. A cap and flow system is a high
pressure system that includes the
capping stack and piping necessary to
convey the flowing fluids through the
choke manifold to the surface
equipment. When a responsible party
has been able to successfully cap a well,
but conditions will not allow the well
to be shut in (e.g., due to damage,
equipment failure or pressure
constraints), the cap and flow system
allows the well cap to be used as a
connection for the flow lines that
transport well fluids to the surface for
capture and disposition. In some
circumstances, this can relieve the
pressure on the capping device or
tubulars at the well head or in the well
while maintaining or reestablishing
control of the produced fluids, or a
portion thereof.
Capping Stack—this term would be
defined to mean a mechanical device
that can be installed on top of a subsea
or surface wellhead or BOP to stop the
flow of fluids into the environment. A
capping stack’s primary function is to
stop the uncontrolled flow of fluids
from a well to the environment in the
event that other intervention methods,
such as a BOP, would fail. The capping
stack is attached to a connector or pipe
stub located on or in the well to achieve
a pressure-tight seal that would either
stop the flow or direct it into a conduit
that would transmit the fluids to a
surface facility that is able to store,
process, or properly dispose of the
fluids. Capping stacks may be deployed
from the surface to the well head, as
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9931
needed, or prepositioned below the riser
system when the BOP is located on the
deck of a MODU. The pre-positioned
capping stack may be created by
adapting an auxiliary subsea
intervention device to meet the
requirements of this proposed rule.
Containment Dome—this term would
be defined to mean a non-pressurized
container that can be used to collect
fluids escaping from the well or
equipment below the sea surface or from
seeps by suspending the device over the
discharge or seep location. A
containment dome, also known as a
‘‘sombrero,’’ ‘‘cofferdam,’’ or ‘‘hat,’’
captures fluids after they have escaped
the well, subsea equipment, or a seep,
but before they have reached the
surface. It consists of a structure that has
the ability to capture fluids rising
through the water column and to convey
the fluids to a surface vessel or facility
for processing or disposal. If a cap and
flow system is unable to stop or control
the flow of fluids to the environment, or
the well system is so damaged that a
capping stack cannot make a successful
connection, the containment dome
system would be needed to capture the
hydrocarbons flowing to the
environment.
Source Control and Containment
Equipment (SCCE)—SCCE would be
defined to mean the capping stack, cap
and flow system, containment dome,
and/or other subsea and surface devices,
equipment, and vessels whose collective
purpose is to control a spill source and
stop the flow of fluids into the
environment or to contain fluids being
discharged into the environment for
proper processing or disposal. This
definition is useful for referring
collectively to the various independent
elements of an operator’s SCCE in
portions of the proposed rule that would
apply to any such equipment and its
capabilities as a unified system, rather
than a specific type of SCCE (see, e.g.,
proposed § 250.470(f)). The SCCE serves
the purpose of stopping or minimizing
the flow of hydrocarbons into the
environment after a loss of well control
event has occurred. The term ‘‘surface
devices’’ within the definition of SCCE
refers to equipment mounted or staged
on a barge, vessel, or facility. The
purpose of this equipment is to separate,
treat, store and/or dispose of fluids
conveyed to the surface by the cap and
flow system or the containment dome.
The SCCE, however, does not include a
BOP or similar equipment that is used
in ordinary operations and functions to
maintain well control under normal
operational conditions or to prevent a
loss of well control. Finally, ‘‘subsea
devices’’ includes, but is not limited to,
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remotely operated vehicles (ROV),
anchors, buoyancy equipment,
connectors, cameras, controls and other
subsea equipment necessary to facilitate
the deployment, operation and retrieval
of the SCCE.
What incidents must I report to BSEE
and when must I report them?
(§ 250.188)
The current regulation requires
operators to provide oral and written
notification to the BSEE District
Manager (who in the Alaska OCS region
is the Regional Supervisor) of, among
other things, any injuries, fatalities,
losses of well control, fires and
explosions, and incidents affecting
operations. BSEE proposes to add a new
paragraph (c) to this section that would
require operators on the Arctic OCS to
provide an immediate oral report to the
BSEE onsite inspector, if one is present,
or to the Regional Supervisor of any sea
ice movement or condition that has the
potential to affect operations or trigger
ice management activities, as well as the
start and termination of these activities,
and any ‘‘kicks’’ or operational issues
that are unexpected and could result in
the loss of well control.
Sea ice, if not properly managed, can
have a major effect on exploratory
drilling operations. Spring and summer
thawing can produce large ice masses
on the waters overlying the Arctic OCS,
which could cause substantial damage
to exploratory drilling equipment and
render operations unsafe, leading to
injury, loss of life, or environmental
harm. For example, if the well is not
properly protected, sea ice that is
moving through the surrounding water
could cause a loss of well control by
damaging the well head and triggering
the discharge of hydrocarbons into the
marine environment. Ice management
activities, as described in an operator’s
ice management plan, could include
physically changing the direction of an
ice floe or using ice breaking techniques
in order to minimize the likelihood of
damage to the exploratory drilling
equipment.
It is essential for operators to remain
in close communication with BSEE
about sea ice in the area that has the
potential to affect operations. Just as the
operator needs to have sufficient time to
act in the event that ice poses an
operational hazard, BSEE would need
sufficient time to oversee the safety of
an operator’s reactions and prepare to
respond if a response is necessary due
to a safety or environmental incident
resulting from an ice event.
The proposed paragraph (c) would
require the operator to immediately
notify the BSEE inspector on location or
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the Regional Supervisor of any event
that, pursuant to the hazard thresholds
identified in its EP, would trigger a
heightened observation requirement, or
could potentially result in the need to
physically manage ice, initiate
operations to secure the well, or move
the drilling rig to avoid a threat caused
by floating ice. This provision would
also require immediate oral notification
of the commencement and completion
of any ice management activities.
The oral report required by this
provision could be a simple direct oral
notification of the basic facts
surrounding the relevant circumstances,
and would not need to contain all of the
detail required of oral reports pursuant
to § 250.189. The proposed provision
would also require a follow-up written
report regarding any ice management
activities undertaken by the operator
that must be submitted within 24 hours
following completion of those activities.
BSEE proposes this tighter 24-hour
timeline (as opposed to, and in lieu of,
the standard 15 day window under
§ 250.190) due to the immediacy of the
threats and concerns presented by
circumstances requiring ice
management activities, and the need for
BSEE to remain abreast of those events
in its regulatory and safety oversight
role. The written report may be
submitted via email or other electronic
means to the inspector or Regional
Supervisor and must conform to the
content requirements set forth in
§ 250.190.
Finally, BSEE proposes to require that
operators submit an immediate oral
report of any ‘‘kicks’’ or operational
issues that are unexpected and could
result in the loss of well control.
Operators on the Alaska OCS currently
have to report kicks at the end of every
day on the well activity report Form
BSEE–0133, as required by § 250.468.
However, the proposed requirements of
this section mean operators would not
be allowed to wait until the end of the
day or some time later to fill out a form.
If a kick occurred, they would have to
provide an immediate oral report. The
nature of Arctic OCS Conditions, as
defined in this proposed rule,
demonstrates that responding to a spill
in the Arctic region would be a difficult
task. Reporting kicks right away is a
safety measure that can improve the
ability of both inspectors and operators
to potentially prevent a loss of well
control.
Documents incorporated by reference.
(§ 250.198)
The proposed rule would add
subsection (h)(89) to existing § 250.198
as a reference to the American
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Petroleum Institute (API) proposed draft
Recommended Practice (RP) 2N,
Recommended Practice for Planning,
Designing, and Constructing Structures
and Pipelines for Arctic Conditions,
Third Edition. This document will be a
voluntary consensus standard
addressing the unique Arctic OCS
Conditions that affect the planning,
design, and construction of systems
used in Arctic and sub-Arctic
environments. This API document—
which is virtually identical to a
standard previously issued by the
International Organization for
Standardization (ISO), ‘‘Petroleum and
Natural Gas Industries Arctic Offshore
Structures,’’ First Edition (2010) (ISO
19906)—would be appropriate for
certain aspects of drilling operations,
such as accounting for the severe
weather and thermal effects on
structures, maintenance procedures, and
safety. Since this proposed rule is
focused on the exploratory drilling
phase of operations on the Arctic OCS,
certain portions of API RP 2N, Third
Edition (such as those related to issues
regarding structural and pipeline
integrity) would not be relevant to the
exploration stage. However, many
elements of that document, when
published, could be effectively applied
to equipment used in exploratory
drilling operations on the Arctic OCS.
Therefore, proposed §§ 250.198(h)(89)
and 250.470(g) would incorporate
appropriate elements of API RP 2N,
Third Edition, for purposes of APD
information requirements.
A voluntary consensus standard
indicates acceptance and recognition
across the industry that certain
technology is feasible. For example, API
standards are created with input from
oil and gas operators, drilling
contractors, service companies,
consultants, and regulators. Even
though the development of a consensus
standard does not necessarily represent
a unanimous agreement by the
developing body’s members, the API
process provides a means for industry
and regulatory bodies to provide input
into the development of protocols for
the highly specialized equipment and
procedures used in oil and gas
operations. In the National Technology
Transfer and Advancement Act of 1995
(Pub. L. 104–113, 15 U.S.C. 3701 note),
Congress directed Federal agencies to
use technical standards that are
developed or adopted by voluntary
consensus standards bodies in lieu of
government-unique standards, unless
inconsistent with applicable law or
otherwise impractical (see OMB
Circular A–119 (Revised), February
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1998, available at www.standards.gov/
standards_gov/nttaa.cfm).
BSEE frequently uses standards (e.g.,
codes, specifications, RPs) developed
through a consensus process, facilitated
by standards development organizations
and with input from the oil and gas
industry, as a means of establishing
requirements for activities on the OCS.
BSEE may incorporate these standards
into its final regulations without
publishing the standards in their
entirety in the Code of Federal
Regulations, a practice known as
incorporation by reference. The legal
effect of incorporation by reference is
that the incorporated standards become
regulatory requirements. Material
incorporated in a final rule, like any
other properly issued regulation, has the
force and effect of law, and BSEE holds
operators, lessees and other regulated
parties accountable for complying with
the documents incorporated by
reference in its final regulations. BSEE
currently incorporates by reference over
100 consensus standards in its offshore
regulations governing oil and gas
operations (see 30 CFR 250.198).
Federal regulations at 1 CFR part 51
govern how BSEE and other Federal
agencies incorporate various documents
by reference. Agencies may only
incorporate a document by reference in
a final rule by publishing the document
title, edition, date, author, publisher,
identification number and other
specified information in the Federal
Register. The Director of the Federal
Register must approve each publication
incorporated by reference in a final rule.
Incorporation by reference of a
document or publication in a final rule
is limited to the specific edition
approved by the Director of the Federal
Register.
and printable versions will continue to
be available for purchase through API.
BSEE proposes to incorporate, with
certain exclusions discussed later in this
proposed rule, draft proposed API RP
2N, Third Edition, which is available for
free public viewing during the API
balloting process on API’s Web site at
http://mycommittees.api.org/standards/
ecs/sc2/default.aspx (click on the title
of the document to open). When
finalized by API, that standard will be
available for free public viewing on
API’s Web site at: http://
publications.api.org.5
In addition, as explained later in this
proposed rule, BSEE is considering
incorporating by reference ISO 19906 in
lieu of API RP 2N, Third Edition. ISO
standards are available for purchase
from ISO at ISO’s publications Web site
at: http://www.iso.org/iso/home/store/
catalogue_ics.htm or from commercial
vendors.6
For the convenience of the viewing
public who may not wish to purchase or
view incorporated documents online,
they may be inspected, upon request, at
our office, 381 Elden Street, Room 3313,
Herndon, Virginia 20170 (phone: 703–
787–1587); or at the National Archives
and Records Administration (NARA).
For information on the availability of
materials at NARA, call 202–741–6030,
or go to: www.archives.gov/federalregister/cfr/ibr-locations.html.
If API RP 2N, Third Edition, is
incorporated into the final rule, it would
continue to be made available for public
viewing, when requested, at the
addresses indicated in the prior
paragraph. Specific information on
where incorporated documents can be
inspected or obtained is also found at
§ 250.198, Documents incorporated by
reference.
Availability of Incorporated Documents
for Public Viewing
When a copyrighted industry
standard is incorporated by reference
into our regulations, BSEE is obligated
to observe and protect that copyright.
We typically provide members of the
public with Web site addresses where
these standards may be accessed for
viewing—sometimes for free and
sometimes for a fee. The decision to
charge a fee is made by each standards
development organization. The API
provides free online public access to at
least 160 key industry standards,
including a broad range of technical
standards. Those standards represent
almost one-third of all API standards
and include all that are safety-related or
are incorporated into Federal
regulations. These standards are
available for review, and hard copies
Pollution prevention. (§ 250.300)
This section would revise BSEE’s
pollution prevention regulation as it
pertains to Arctic OCS exploratory
drilling operations. Spent mud and
cuttings are generated during
exploratory drilling. Drilling mud may
be entirely water-based or may include
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5 To access a standard at that API Web site, first
log-in or create a new account, accept API’s ‘‘Terms
and Conditions,’’ then click on the ‘‘Browse
Documents’’ button, and then select the applicable
category (e.g., ‘‘Exploration and Production’’) for
the particular standard(s) you wish to review.
6 Copies of the ISO standards referred to in this
proposed rule may also be viewed, upon request,
at BSEE’s Regional Offices for Alaska (3801
Centerpoint Dr., Suite 500, Anchorage, AK; 907–
334–5300), the Pacific (760 Paseo Camarillo,
Camarillo, CA; 805–384–6300), and the Gulf of
Mexico (1201 Elmwood Park Blvd., Nw Orleans,
LA; 1–800–672–2627) and at BSEE’s Houston office
(701 San Jacinto St., Rm. 115, Houston, TX; 713–
220–9201).
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petroleum (i.e., oil) as a component.
Cuttings generated using petroleumbased mud would be oil-contaminated,
and the discharge of the mud or cuttings
into the environment would result in
discharge of that oil into the
environment. The proposed rule would
add provisions in paragraphs (b)(1) and
(b)(2) requiring that, during exploratory
drilling operations on the Arctic OCS,
the operator must capture all petroleumbased mud, and associated cuttings from
operations that use petroleum-based
mud, to prevent their discharge into the
marine environment. These
subparagraphs would also clarify the
Regional Supervisor’s discretionary
authority to require operators to also
capture all water-based mud and
associated cuttings from Arctic OCS
exploratory drilling operations (after
completion of the hole for the conductor
casing) to prevent their discharge into
the marine environment, based on
factors including, but not limited to:
1. The proximity of the exploratory
drilling operations to subsistence
hunting and fishing locations;
2. The extent to which discharged
mud or cuttings may cause marine
mammals to alter their migratory
patterns in a manner that interferes with
subsistence activities; or
3. The extent to which discharged
mud or cuttings may adversely affect
marine mammals, fish, or their habitat.
BSEE regulates discharges of mud and
cuttings from OCS facilities under the
OCSLA, which contemplates the
imposition of environmental safeguards
for oil and gas activities on the OCS and
mandates that they be conducted in a
manner that prevents or minimizes the
likelihood of damage to the
environment. The President has also
delegated authority to the Secretary
(further delegated to BSEE) to regulate
discharges of oil under Section 311 of
the CWA, 33 U.S.C. 1321, which calls
for the issuance of regulations
establishing procedures, methods, and
equipment to prevent discharges of oil
and hazardous substances from offshore
facilities, and to contain such
discharges. BSEE’s pollution prevention
regulations are intended to complement
requirements imposed by the EPA under
the CWA. For example, in November
2012, the EPA issued general National
Pollutant Discharge Elimination System
(NPDES) permits authorizing certain
discharges from oil and gas exploratory
facilities to Federal waters in the
Beaufort Sea and the Chukchi Sea,
including certain discharges of waterbased drilling fluids and drill cuttings,
subject to effluent limitations and other
requirements. Of note, the EPA NPDES
permits do not allow the discharge of
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oil-based drilling fluids, or the
discharge of water-based drilling fluids
and drill cuttings during the fall
bowhead whale hunt in the Beaufort
Sea. BSEE’s proposed regulations clarify
the Regional Supervisor’s authority to
impose operational measures that
complement EPA’s discharge limitations
by considering potential impacts to
specific components of the Arctic
environment, such as subsistence
activities, marine resources, and coastal
areas.
The discharge of mud and cuttings
has the potential to affect marine
mammals, fish, and their habitat, as well
as subsistence activities present in the
Arctic region. As noted earlier,
subsistence hunting is central to the
food supply and cultural traditions of
many Alaska Natives. BSEE proposes to
clarify its authority to limit discharges
of any mud and cuttings having the
potential to adversely impact marine
wildlife or to disrupt subsistence
hunting activities.
For example, existing environmental
analyses show that the release of drill
cuttings and drilling mud would result
in increased turbidity and
concentrations of total suspended solids
in the water column, which could
displace marine mammals from the drill
sites and could adversely affect habitat
and prey within and around the drill
site (see Shell Gulf of Mexico, Inc.’s
Revised Chukchi Sea Exploration Plan
Burger Prospect Environmental
Assessment (2011)). In addition,
subsistence hunters, who rely on
traditional ecological knowledge, have
expressed concern to BOEM and BSEE
that whales are capable of detecting the
odors from mud and cuttings and will
avoid areas where these discharges
occur, resulting in similar effects.
Hunting farther away from shore to find
displaced whales can increase transit
time, reduce the likelihood of successful
harvests, increase exposure to adverse
weather and dangerous sea states, and
increase safety concerns for subsistence
hunters. Finally, the farther away
whales are harvested from a community,
the greater the length of towing time
necessary to bring the animals back to
shore for processing. This increased tow
time could negatively affect the viability
of the meat and blubber for food because
of spoilage.
Marine mammal migrations and
subsistence hunting patterns vary
greatly in different areas of the Arctic
region and at different times of the year.
These proposed rules would therefore
clarify the Regional Supervisor’s
discretion to require the capture of
water-based mud and cuttings, taking
into account location- and season-
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specific circumstances (such as
subsistence hunting). In addition, other
relevant circumstances, such as
applicable provisions of a NPDES
general permit, can be considered when
exercising that discretionary authority.
BSEE invites comments on the potential
costs to the industry of limiting or
prohibiting the discharge of mud and
cuttings that otherwise would not be
prohibited by the NPDES general
permits.
When and how must I secure a well?
(§ 250.402)
The current regulation requires,
among other things, that operators
install a downhole safety device at an
appropriate depth whenever there is an
interruption in drilling operations.
BSEE proposes to add a new paragraph
(c)(1), which would require exploratory
drilling operators on the Arctic OCS to
ensure that any equipment left on, near,
or in a temporarily abandoned well that
has penetrated below the surface casing
be secured in a way that would protect
the well head and prevent or minimize
the likelihood of the integrity of the well
or plugs being compromised. The
primary concern this proposed language
is designed to address is the possibility
that ice floes could sever, dislodge, or
drag any exploration-related equipment,
obstructions or protrusions left on the
well or the adjacent seafloor. The
proposed language, however, is drafted
to encompass damage from any
foreseeable source. The provision in
paragraph (c)(1) is designed to be
performance-based, would allow
operators to devise optimal strategies for
identifying and accounting for threats to
the integrity of equipment left on the
OCS, and would be limited only to
exploration wells that have penetrated
below the surface casing. However, for
exploration wells located in an area
subject to ice scour, based on a shallow
hazards survey, proposed paragraph
(c)(2) would require a mudline cellar or
equivalent means of protection. The
BSEE Regional Supervisor will evaluate,
during the APD process, whether a
proposed equivalent approach is
sufficiently protective.
There are a number of problems that
could occur if operators did not adhere
to this proposed requirement. For
example, if an ice floe were to contact
equipment left on, near, or in a well that
had penetrated hydrocarbons, the
impact could damage the well and
potentially compromise the cement,
casing, or safety valves and plugs inside
the well and could result in the
discharge of hydrocarbons.
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What additional information must I
submit with my APD? (§ 250.418)
BSEE proposes to add a new
paragraph (k) to this section, providing
that the information identified in
proposed § 250.470 must be submitted
with an APD for exploratory drilling on
the Arctic OCS. The information
required in the proposed section would
be necessary to inform BSEE’s
evaluation of APDs for Arctic OCS
exploratory drilling operations (see
discussion of proposed § 250.470).
When must I pressure test the BOP
system? (§ 250.447)
The current regulation requires
operators to pressure test a BOP system
when it is installed, at specified time
intervals, and prior to drilling out each
string of casing or a liner. BSEE
proposes to revise paragraph (b) of this
section to require a BOP pressure test
frequency of one test every 7 days for
Arctic OCS exploratory drilling
operations. However, there is some
debate over whether more frequent
testing, beyond the 14-day test
frequency prescribed by existing
regulations, would be necessary or
advisable.
The effectiveness of hydrostatic
pressure testing of BOPs has been
questioned in the past. The industry has
argued that increasing the number of
pressure tests: (1) may reduce the
reliability of the equipment by
degrading the sealing capability of the
elements within the BOP stack; and (2)
does not necessarily demonstrate the
future performance of the equipment.
Furthermore, the industry has claimed
that the requirement for operators to
stop drilling operations to perform a
pressure test could ultimately increase
the likelihood of an incident occurring.
Due to these safety and cost concerns,
the industry has sought to reduce the
current testing frequency for this
equipment (i.e., to longer than every 14
days).
Ensuring the proper functioning of a
BOP, which is a critical line of defense
against loss of well control, is essential
to Arctic OCS drilling operations. BSEE
is concerned that the integrity of BOPs
could be compromised by Arctic
conditions; in particular, BSEE is
concerned about the possible effects of
extreme weather conditions on BOPs
maintained on surface vessels or
facilities (such as jackup rigs). At this
time, pressure tests and functional tests
are the primary methods for ensuring
the performance of BOPs. A 7-day BOP
testing cycle was proposed by Shell in
2012, and ultimately approved by BSEE,
and we propose to require a similar
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testing frequency for all Arctic OCS
exploratory drilling operations. BSEE
specifically requests comments on the
appropriateness of the proposed 7-day
testing frequency to demonstrate the
reliability of the equipment under
Arctic conditions. BSEE also requests
that commenters identify any additional
safety issues that might arise from this
increased testing and that would be
unique to Arctic operations. In addition,
BSEE invites comments on all potential
drilling impacts related to the proposed
7-day testing frequency.
Note that the only proposed changes
to the existing BOP testing regulation
are the phrases specific to exploratory
drilling on the Arctic OCS. The
remaining language is identical to the
wording currently at § 250.447(b) and is
duplicated in this proposed rule for
readability.
What are the real-time monitoring
requirements for Arctic OCS exploratory
drilling operations? (§ 250.452)
BSEE proposes to add a new
performance-based section in Part 250
that would require real-time data
gathering on the BOP control system,
the fluid handling systems on the rig,
and, if a downhole sensing system is
installed, the well’s downhole
conditions during Arctic OCS
exploratory drilling operations. In
addition, this section would require
operators to transmit immediately the
data during operations to an onshore
location, identified to BSEE prior to
well operations, where it must be stored
and monitored by personnel who would
be capable of interpreting the data and
have the authority, in consultation with
rig personnel, to initiate any necessary
action in response to abnormal events or
data. Such personnel must also have the
capability for continuous and reliable
contact with rig personnel, to ensure the
ability to communicate information or
instructions between the rig and
onshore facility in real-time, while
operations are underway.
This section would be added, in part,
based on multiple recommendations
from various Deepwater Horizon
investigation reports. Having the realtime, well-related data available to
onshore personnel would increase the
level of oversight of well conditions
during operations. Onshore personnel
could review data and help rig
personnel conduct operations in a safe
manner. Also, onshore personnel would
be able to assist the rig crew in
identifying and evaluating abnormalities
that might arise during operations. This
section would also require that the realtime monitoring data be available to
BSEE upon request, to enable BSEE to
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perform its oversight role and to
monitor responses to events as they
unfold. Finally, this section would,
consistent with §§ 250.466 and 250.467,
require that the data gathered be stored
at a designated location for
recordkeeping purposes after operations
have concluded, to enable BSEE to
perform audits, investigations, or other
types of analyses, as part of its
regulatory oversight functions.
The following undesignated centered
heading would be inserted above
proposed § 250.470:
Additional Arctic OCS Requirements
What additional information must I
submit with my APD for Arctic OCS
exploratory drilling operations?
(§ 250.470)
BSEE proposes to add § 250.470,
which would require operators to
provide Arctic OCS-specific information
with their APDs for exploratory drilling.
The proposed informational
requirements in the new section would
be necessary to inform BSEE’s
evaluation of APDs for Arctic OCS
exploratory drilling operations.
Paragraph (a), Fitness for Service
This provision would require
operators to submit a detailed
description of the environmental,
meteorologic and oceanic conditions
expected at the well site(s); how their
equipment, materials, and drilling unit
will be prepared for service in the
conditions, and how the drilling unit
will be in compliance with the
requirements of § 250.417. For this
proposed requirement, BSEE would
expect the operator to identify the
specific drilling units proposed for use
during its operations, verify that the
identified equipment and materials are
fit for service, and that the drilling units
conform to the fitness for service
requirements of § 250.417. It is
important that operators provide this
level of detail to ensure that the
equipment, materials, and drilling units
proposed for use in Arctic OCS
exploratory drilling are capable of
performing their respective tasks under
Arctic OCS Conditions.
The information requested by this
proposed section for drilling units is not
in addition to the requirements of
§ 250.417, but rather is designed to
make clear that, to satisfy the fitness
requirements of § 250.417, operators
would need to provide details regarding
Alaska OCS Conditions. Further, BSEE
does not currently have an existing
provision for drilling equipment and
materials that requires the same level of
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detail found in § 250.417 for drilling
units.
BSEE’s current regulations concerning
fitness for other types of equipment and
material are more general and
performance-based than the
requirements proposed in this rule for
Arctic OCS operations. Additionally,
since SCCE is a new suite of equipment
and materials proposed by this rule,
there are no existing fitness for service
regulations covering these items.
Therefore, the information required
under proposed paragraph (a) for
equipment and materials would be new.
Paragraph (b), Well-specific Transition
Operations
This provision would require
operators to submit ‘‘[a] detailed
description of all operations necessary
in Arctic OCS Conditions to transition
the rig from being under way to
conducting drilling operations and from
ending drilling operations to being
under way, as well as any anticipated
repair and maintenance plans for the
drilling unit and equipment.’’ BSEE
does not intend for this provision to
require operators to resubmit any
information already submitted to
BOEM. Rather, BSEE would expect
operators to have a fairly detailed plan
when they submit their APD, including
information such as the identity of
equipment and vessels to be used, dates
of planned operations, and a description
of how the equipment and vessels
would be designed for and be capable of
performing in Arctic OCS Conditions.
For transition operations, BSEE would
need details about all of the activities
necessary to begin and end drilling
operations, and to move from one
drilling location to the next. Examples
of the types of activities BSEE would
expect an operator to describe include,
but are not limited to: recovering the
subsea equipment, including the marine
riser and the lower marine riser
package; recovering the BOP; recovering
the auxiliary sub-sea controls and
template; laying down the drill pipe and
securing the drill pipe and marine riser;
securing the drilling equipment;
transferring the fluids for transport or
disposal; securing ancillary equipment
like the draw works and lines; refueling
or transferring fuel; offloading waste;
recovering the ROVs; picking up the oil
spill prevention booms and equipment;
and offloading the drilling crew.
Finally, BSEE would require
information regarding any specific
repair and maintenance plans for the
drilling unit and equipment associated
with commencement or completion of
drilling operations. All of the required
information would facilitate BSEE’s
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understanding of an operator’s program
and ensure that the operator complies
with lease stipulations, EP conditions,
and other permitting requirements.
Paragraph (c), Well-specific Drilling
Objectives and Contingency Plans
This provision would require
operators to submit ‘‘[w]ell-specific
drilling objectives, timelines, and
updated contingency plans for
temporary abandonment of the well.’’
Whereas the corresponding provisions
of the proposed IOP and current EP
regulations (e.g., § 550.211) relate more
broadly to the objectives and timelines
of the overall proposed exploratory
drilling activities, this provision would
require an operator to provide ‘‘wellspecific’’ information at the APD stage.
This information would include the
operator’s detailed schedule of the
following:
1. When they will spud the particular
well (i.e., begin drilling operations at the
well site) identified in the APD;
2. How long will it take to drill the
well;
3. Anticipated depths and geologic
targets, with timelines;
4. When the operator expects to set
and cement each string of casing;
5. When and how the operator would
log the well;
6. The operator’s plans to test the
well;
7. When and how the operator would
abandon the well, including specifically
addressing plans for how to move the
rig off location and how the operator
would meet the requirements of
proposed § 250.402(c);
8. A description of what equipment
and vessels would be involved in the
process of temporarily abandoning the
well due to ice; and
9. An explanation of how these
elements would be integrated into the
operator’s overall program.
Examples of the information the
operator would be required to provide
include, but are not limited to: the
location(s) to which the rig would be
moved; the operator’s plans for safely
securing the well prior to leaving the
drill site; how temporary abandonment
would affect the operator’s seasonal
drilling plans, including its remaining
schedule of operations at each well; and
how crew logistics, such as
transportation to and from a drilling rig,
would be affected.
It should be noted that the
contingency plans proposed in this
section of the rule are different from the
contingency plans required for ‘‘icing or
ice-loading’’ under existing
§ 250.417(c)(2). That phrase refers to ice
build-up on the vessel or equipment
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itself, whereas the focus of proposed
§ 250.470(c) is on ice management,
meaning the contingency plans for
response to the presence of ice in the
water, such as temporary abandonment
of a well until the ice in the water
passes, or management through some
other technique. For oil and gas
exploration, ice management is an
Arctic OCS-specific issue that does not
occur elsewhere on the OCS. However,
icing and ice-loading can occur during
operations on other parts of the OCS,
outside of the Arctic.
Paragraph (d), Weather and Ice
Forecasting and Management
This performance-based provision
would require an operator to submit: a
detailed description of its ‘‘weather and
ice forecasting capability for all phases
of the drilling operation, including how
[it] will ensure continuous awareness of
potential weather and ice hazards at,
and during transition between, wells;’’
its ‘‘plans for managing ice hazards and
responding to weather events;’’ and
verification that it has the capabilities
described in its EP. Verification could
be provided, for example, by providing
appropriate supporting documents (e.g.,
contracts) for the forecasting and ice
management capabilities.
BSEE needs to know the details for
how the operator would implement the
policies and/or plans for managing ice
and weather events, identified to BOEM,
for the drilling operations proposed in
the APD. It is anticipated that the
operator may not know the specific
details about each vessel and piece of
equipment that contributes to its
weather and ice forecasting and
management capabilities when
describing those capabilities to BOEM,
in connection with the IOP and the EP.
Also, more detailed plans for managing
ice hazards or weather events may be
necessary and appropriate given the
timing and location of the specific well
at issue than may have been available or
appropriate for the IOP and EP. Further,
BSEE anticipates that weather and ice
monitoring and forecasting capabilities
may evolve between the approval of the
EP and the submittal of the APD, which
could yield better data, especially when
operations commence. Therefore, this
proposed provision would require the
operator to submit the specific detailed
information to BSEE in connection with
its APD and also to describe, in more
detail and closer in time to
commencement of drilling, how it
would implement its weather and ice
forecasting and management plan.
BSEE would expect operators to
identify the specific weather and ice
forecasting equipment and vessels that
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they intend to utilize, including the
name of the contractor that would
deliver satellite imagery, if applicable.
Such information should also be
specific to the location and operations
associated with the well that is the
subject of the particular APD.
Finally, BSEE would require that an
operator’s weather and ice management
capabilities would be uninterrupted for
the entirety of their operations while on
the Arctic OCS. This provision proposes
that there would be no gap in weather
and ice monitoring activities, including
during transit between wells. This is to
ensure that, upon arrival at a new well
location, there are no unexpected
weather or ice hazards that would
interfere with drilling operations at the
new location, or would pose a threat to
the safety or integrity of the drilling
equipment or personnel. The purpose of
this proposed requirement is to ensure
that hazards to drilling operations are
avoided or managed before they could
become a danger or an interruption to
operations.
Paragraph (e), Relief Rig Plan
Paragraph (e) would require operators
to provide, with their APD, information
concerning how they would comply
with the relief rig requirements of
proposed § 250.472. See the discussion
of that provision for an explanation of
the nature of, and need for, those
requirements.
Paragraph (f), SCCE Capabilities
Paragraph (f) would require operators
who propose to use a MODU to conduct
exploratory drilling operations on the
Arctic OCS to provide with their APD
information concerning their required
SCCE capabilities when they are drilling
below or working below the surface
casing, including a statement that the
operator owns, or has a contract with a
provider for, SCCE capable of
controlling and/or containing its
identified WCD. Ensuring that an
operator would be capable of
responding to a loss of well control is
one of the key goals of this proposed
rule. In other parts of the OCS (e.g., the
Gulf of Mexico), there are several wellestablished contractors readily available
to operators and extensive operations
and infrastructure within the region
from which resources could be drawn to
respond to an event. However, resources
are limited in the Arctic region due to
the remote location and relative lack of
infrastructure and operations. Therefore,
operators proposing to conduct
exploratory drilling on the Arctic OCS
must demonstrate that they would have
access to, and be capable of promptly
deploying, adequate SCCE. Operators
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must also describe how they would
inspect, test, and maintain this
equipment in order to ensure that it
would remain fully functional and
ready for use. These proposed
requirements would help assure BSEE
that operators conducting exploratory
drilling under Arctic OCS Conditions
are capable of: (1) Regaining control
after a loss of well control event or (2)
containing escaping fluids from a loss of
well control event. The information
requirements of paragraph (f) would
include:
1. A detailed description of the
operator’s or its contractor’s SCCE
capabilities. The description must
include operating assumptions and
limitations and information
demonstrating that the operator would
have access to and the ability to deploy
such equipment necessary to regain
control of the well. This description
would allow BSEE to verify the location
and availability of this equipment for
compliance with proposed § 250.471.
2. An inventory of the equipment,
supplies, and services the operator owns
or has a contract for locally and
regionally, including the identification
of each supplier. This information is
important because BSEE would need to
verify the existence, condition, and
location of the equipment that the
operator describes in its plans.
3. Where SCCE capabilities are
obtained through contracting, proof of
contracts or membership agreements
with cooperatives, service providers, or
other contractors, including information
demonstrating the availability of the
personnel and/or equipment on a 24hour per day basis during operations
below the surface casing. In an effort to
minimize the environmental and social
footprint of, and economic impediments
to, Arctic OCS operations, BSEE is
encouraging operators to share
resources, especially standby
equipment. This provision would
facilitate the identification of those
assets, and would allow BSEE to verify
the contractual basis of any agreements
necessary to provide the services
required.
4. A description of the procedures for
inspecting, testing, and maintaining
SCCE. SCCE is intended to be standby
equipment. However, BSEE needs to be
assured that the equipment would
remain able to function if it were
needed. This provision would allow
BSEE to verify that the operator, or
contractor, has procedures in place for
inspecting, testing, and maintaining the
equipment so that it would be ready for
use, if necessary. Operators are already
required under existing regulations at
§ 250.1916 to retain the information
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requested by this proposed new
paragraph. The proposed provision
would require that operators who
propose to conduct exploratory drilling
on the Arctic OCS submit this
information in conjunction with their
APD.
5. A description of the operator’s plan
to ensure that personnel are trained to
deploy and operate the equipment and
that they would maintain ongoing
proficiency in source control operations.
Standby crews who are not used
regularly to perform their dedicated
functions would not develop the
necessary skills unless they are properly
trained, and would not maintain those
skills unless that training is reinforced
by practice. It is therefore imperative
that the operator demonstrate that these
personnel have a plan for acquiring, and
the ability to maintain, the proficiency
necessary to respond when called upon.
This requirement would allow BSEE to
review those plans and verify that the
proficiencies have been acquired and
would be maintained.
Paragraph (g), API RP 2N, Third Edition
Paragraph (g) would require that
operators explain how they utilized API
RP 2N, Third Edition, in planning their
Arctic OCS exploratory drilling
operations. The API is updating this RP
by adopting the entirety of ISO standard
‘‘Petroleum and natural gas industries
Arctic offshore structures,’’ First Edition
(2010) (ISO 19906). Since the
requirements of this proposed rule are
limited only to exploratory drilling
operations, operators would not be
expected to provide an explanation of
how they utilized the entire API RP 2N,
Third Edition. This performance-based
requirement would be limited to those
portions of that document that are
specifically relevant for exploratory
drilling operations. BSEE proposes to
exclude the following sections of API
RP 2N, Third Edition, from
incorporation:
1. sections 6.6.3 through 6.6.4;
2. the foundation recommendations in
section 8.4;
3. section 9.6;
4. the recommendations for
permanently moored systems in section
9.7;
5. the seismic analysis
recommendations for pile foundations
in section 9.10;
6. section 12;
7. section 13.2.1;
8. sections 13.8.1.1, 13.8.2.1, 13.8.2.2,
13.8.2.4 through 13.8.2.7;
9. sections 13.9.1, 13.9.2, 13.9.4
through 13.9.8;
10. sections 14 through 16; and
11. section 18.
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Sections 6.6.3 and 6.6.4 would be
excluded because they address different
types of conditions for ice gouging and/
or scouring than are anticipated to occur
during the Alaska Arctic open water
drilling season. The foundation criteria
of section 8.4, the piled structure
criteria of section 9.6, the requirements
for permanently moored systems in
section 9.7, and the requirements for
seismic analysis of pile foundations in
section 9.10 would be excluded because
this rule only applies to MODUs drilling
on a temporary basis, as opposed to the
more permanent types of structures
addressed in those provisions.
Similarly, section 12 would be excluded
because it applies only to fixed concrete
structures and is outside the scope of
this proposed rule. Section 13.2.1
(design philosophy for floating
structures) would be excluded because
similar ice forecasting and management
issues are covered separately under
proposed § 250.470(d). Sections
13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4
through 13.8.2.7, 13.9.1, 13.9.2, and
13.9.4 through 13.9.5, would be
excluded because they cover vessel
design and procedures requirements
under USCG jurisdiction. Sections
13.9.6 (inspection and maintenance),
13.9.7 (operations and planning for
safety of personnel, the environment,
and equipment), and 13.9.8 (ice
management plans) would be excluded
because similar requirements are
addressed by other provisions of this
proposed rule. Section 14 would be
excluded because it relates only to
subsea production systems while this
proposed rule applies to MODUs
engaged in exploratory drilling activities
and because this rule proposes a
different set of requirements for BOPs
from that set forth in section 14.3.3.
Section 15 (topsides design and
operation) would be excluded because it
does not generally apply to MODUs, and
any parts that could be utilized for
MODUs fall under USCG jurisdiction.
Section 16 (ice engineering topics)
would be excluded because it applies to
structures that will remain in the ice
and does not apply to MODUs. Section
18 (escape, evacuation and rescue)
would be excluded because its
provisions are already addressed under
existing 30 CFR part 250 Subpart S and
USCG rules.
BSEE recognizes that, when applied
to MODUs, many of the structural
criteria of API RP 2N, Third Edition, are
regulated by the USCG and may be
covered by Class requirements for
marine structures. Classification is a
determination made by private
organizations (in accordance with USCG
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requirements) that a vessel has been
constructed and maintained in
compliance with industry standards to
be fit for a particular service, in this case
Ice Class 3. Therefore, application of
API RP 2N, Third Edition, for the
purposes of this proposed rule would be
limited to the non-marine structural
components of MODUs. For example,
Class requirements do not cover the
derrick, plumbing, pipes, tubing, and
pumps that are all also structural
components of a MODU and that fall
under BSEE jurisdiction. If incorporated
in the final rule, BSEE would expect
operators to comply with API RP 2N,
Third Edition, for MODU components
within BSEE jurisdiction. BSEE and the
USCG have signed a Memorandum of
Agreement for MODUs outlining the
allocation of responsibilities between
the agencies for fixed offshore facilities
available at: www.bsee.gov/BSEENewsroom/Publications-Library/
Interagency-Agreements/; click on the
link for 2013 BSEE/USCG MOA: OCS–
08.
BSEE specifically requests comment
on proposed draft API RP 2N, Third
Edition, and on the extent to which
BSEE should incorporate its provisions
when finalized into the regulations. As
an alternative to incorporation of API
RP 2N, Third Edition, BSEE is
considering incorporation by reference
of ISO 19906, the ISO Arctic standard
on which API RP 2N, Third Edition, is
based. If BSEE incorporates the ISO
standard in lieu of the API standard, the
final rule would exclude the sections of
the ISO standard corresponding to the
excluded sections of API RP 2N
previously discussed. BSEE requests
comments on whether and to what
extent BSEE should incorporate ISO
19906 in lieu of proposed draft API RP
2N, Third Edition.
BSEE is also considering
incorporating the ISO standard
‘‘Petroleum and natural gas industries—
Site-specific assessment of mobile
offshore units—Part 1: Jack-ups,’’ First
Edition (2012) (ISO 19905–1), into the
final rule, with application limited only
to Arctic OCS exploratory drilling
operations. ISO 19905–1 may be better
suited than API RP 2N (or ISO 19906)
to guide structural components for jackup rigs. The API RP 2N (or ISO 19906)
and ISO 19905–1 documents together
would provide the most comprehensive
structural requirements for the use of a
jack-up rig in Arctic conditions. BSEE
requests comments on the extent to
which ISO 19905–1 should be
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incorporated into these proposed Arctic
regulations.7
What are the requirements for Arctic
OCS source control and containment?
(§ 250.471)
BSEE proposes to require operators to
continue to adhere to all applicable
source control and containment
requirements in the current regulations,
and to meet additional SCCE
requirements for Arctic OCS exploratory
drilling operations. BSEE is required to
ensure that offshore oil and gas
operations are conducted safely and in
a manner that protects the environment
from harm as a result of those
operations. As stated earlier, the waters
and surrounding environment of the
Arctic region support a wide variety of
marine mammals and other wildlife,
including several Endangered Species
Act (ESA) listed species and designated
critical habitat. Furthermore, U.S.
obligations under Article 4 of the Arctic
Council’s Agreement on Cooperation on
Marine Oil Pollution Preparedness and
Response in the Arctic, require that, for
‘‘areas of special ecological
significance,’’ each party ‘‘shall
establish a minimum level of prepositioned oil spill combating
equipment, commensurate with the risk
involved, and programs for its use[.]’’
The Arctic contains areas of ecological
significance to the Nation as a whole,
and especially to Alaska Native
communities.
Therefore, it is imperative that any
loss of well control during oil and gas
exploratory drilling operations is
corrected and/or contained as quickly as
possible to minimize the impact of oil
pollution on the environment. To
accomplish this task, it would be
necessary to have all equipment needed
to cap and/or contain the release of
fluids readily available in the event of
a loss of well control during Arctic OCS
exploratory drilling operations. Further,
operations on the Arctic OCS are
distinct from operations on any other
part of the OCS. The logistics and the
transit times necessary to respond to a
well control event on the Arctic OCS,
coupled with the difficulties associated
with oil spill response operations in
Arctic OCS Conditions, require the
operator to plan for and be prepared for
contingencies that would be more
7 Copies of ISO 19905–1 may be purchased from
ISO on its Web site (at http://www.iso.org/iso/
home/store/catalogue_ics.htm) or from commercial
vendors. Copies of the ISO standards referred to in
this proposed rule may also be viewed, upon
request, at BSEE’s Herndon, VA, office (at the
address previously) indicated or at BSEE’s Regional
Offices for Alaska, the Pacific, and the Gulf of
Mexico.
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straightforward to address in other
theaters. There is limited ability in the
Arctic region to summon additional
source control and containment
resources. Accordingly, operators
working there must plan for response
redundancies and planning
complexities not required elsewhere.
The proposed requirements would
apply to all exploratory drilling
operations using a MODU on the Arctic
OCS, regardless of the BOP
configuration employed by the
operation. These provisions are
designed to ensure that each operator
using a MODU would have access to,
and could promptly and effectively
deploy and operate, surface and subsea
control and containment equipment in
the event of a loss of well control. In
particular, BSEE would require each
operator to have the ability, in the event
of a loss of well control, to cap the well
and to capture, contain, and process or
properly dispose of any fluids escaping
from the well. All SCCE must be
mobilized (i.e., begin transit) to the well
immediately upon a loss of well control.
The rule would specifically provide that
the SCCE is only necessary when
drilling below or working below the
surface casing.
This new section would require
compliance with the following source
control and containment requirements
for all exploration wells drilled on the
Arctic OCS.
Paragraph (a), Drilling Below or
Working Below the Surface Casing
Paragraph (a) would require that the
operator, when using a MODU to drill
below or work below the surface casing,
have access to a capping stack
positioned to arrive at the well within
24 hours after a loss of well control, and
a cap and flow system and a
containment dome positioned to arrive
at the well within 7 days after a loss of
well control. These technologies are
important because they have, either
individually or in sequence, been
proven to be effective at reacquiring
control of wells and/or containing the
flow of hydrocarbons after primary well
control measures (such as well design
and a BOP) have failed to prevent a well
control event. The SCCE is intended to
provide redundancy in the event of a
loss of well control. Some of the well
control events for which this equipment
would be deployed could require a
relief well to permanently plug and
abandon the uncontrolled well.
On the Arctic OCS, the exploratory
drilling operator would not be
considered to have the required SCCE
unless it is secured in advance and has
the capability of arriving at the well
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within the required timeframes. In the
event that a BOP or other prevention
mechanism fails to stop the flow of
fluids, capping stacks would be
necessary to provide an additional
means to control flow from the well,
where a stub or connector is accessible.
Capping stacks are the preferred
immediate first level redundancy, with
the goal of controlling the well and
stopping the discharge of fluids, and
should be positioned so that they will
arrive at the well within 24 hours after
a loss of well control. Incidents in
which the connectors or tubulars are not
damaged would lend themselves to the
use of a capping stack.
If the tubulars are damaged and the
pressure cannot be managed with the
capping stack, the remainder of the cap
and flow system must be used as a
secondary response. It must be
positioned so that it will arrive at the
well within 7 days of a loss of well
control and designed to capture the
WCD identified in the EP. If the cap and
flow system were unable to stop or
control the flow of fluids to the
environment, or the well system were
damaged to the point that the capping
stack could not make a connection, the
containment dome system, which also
must be positioned to arrive at the well
within 7 days of a loss of well control,
would need to be used to capture the
hydrocarbons flowing to the
environment, as a tertiary response.
Thus, the SCCE system, as a whole,
would provide a level of redundancy
and flexibility necessary to operate on
the Arctic OCS.
BSEE specifically requests comment
on all of the proposed timeframes for
arrival of SCCE at the well in the event
of a loss of well control. In particular,
BSEE invites comments on whether
such timeframes are appropriate, from a
logistical and feasibility perspective, to
address a loss of well control. BSEE also
requests comment on whether the cap
and flow system and containment dome
could be available and positioned to
arrive at the well within 3 days, or some
shorter amount of time than 7 days.
Paragraph (b), Stump Test
Paragraph (b) would require monthly
stump tests of dry-stored capping stacks,
and stump tests prior to installation for
pre-positioned capping stacks. The
presence of the equipment alone is not
sufficient to ensure the reliability of the
system. Testing of the equipment must
be done on a regular basis. This
proposed rule would impose a
requirement that any capping stack that
is dry stored must be stump tested
(function and pressure tested to
prescribed minimum and maximum
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pressures on the deck in a stand or
stump where it could be visually
observed) monthly. The rule would also
require that pre-positioned capping
stacks be tested prior to each
installation on a well to assure BSEE
that no damage was done during the
prior deployment or transit.
Paragraph (c), Reevaluating SCCE for
Well Design Changes
Paragraph (c) would require a
reevaluation of the SCCE capabilities if
the well design changes because some
well design changes may impact the
WCD rate. If the operator proposes a
change to a well design that impacts the
WCD rate, the operator must provide the
new WCD rate through an Application
for Permit to Modify (APM), as required
by § 250.465(a). The operator must then
verify that the SCCE would either be
modified to address the new rate or that
the previously proposed system would
be adequate to handle the new WCD to
demonstrate ongoing compliance with
the SCCE capability requirements
previously addressed.
Paragraph (d), SCCE Tests or Exercises
Paragraph (d) would require the
operator to conduct tests or exercises of
the SCCE when directed by the Regional
Supervisor. Similar to the requirement
that equipment be tested periodically,
BSEE has concluded that there is a need
to ensure that personnel are prepared
and that they, and the SCCE, would be
capable of performing as intended.
Therefore, BSEE proposes to require that
operators conduct tests and exercises
(including deployment), at the direction
of the Regional Supervisor, to verify the
functionality of the systems and the
training of the personnel.
Paragraphs (e) and (f), SCCE Records
Maintenance
Paragraph (e) would require the
operator to maintain records pertaining
to testing, inspection, and maintenance
of the SCCE for at least 10 years, and
make them available to BSEE upon
request. This information would
facilitate a review of the effectiveness of
the operator’s inspection and
maintenance procedures and provide a
basis of review for performance during
any drill, test, or necessary deployment.
Because of the limited drilling season
on the Arctic OCS, the 10-year record
retention requirement is necessary in
order to ensure the availability of a
meaningful longitudinal data set.
Additionally, the limited drilling season
means that this equipment would be
infrequently used and might be stored
for long periods of time between
seasons. Thus, a 10-year record
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9939
retention requirement is necessary to
ensure enough cumulative data is
gathered to assess overall equipment
performance and trends.
Paragraph (f) would require the
operator to maintain records pertaining
to use of the SCCE during testing,
training, and deployment activities for
at least 3 years and to make them
available to BSEE upon request. The use
of the equipment during testing and
training activities and actual operations
must be recorded, along with any
deficiencies or failures. These records
would allow BSEE to address any issues
arising during the usage and to
document any trends or time-dependent
problems that would develop over the
record retention period. In the event
that the equipment is used in a well
control incident, the records are
necessary to document the effectiveness
of the response and functioning of the
equipment.
Paragraphs (g) and (h), Mobilizing and
Deploying SCCE
Paragraph (g) would require operators
to mobilize (i.e., initiate transit of) SCCE
to a well immediately upon a loss of
well control and deploy (i.e., position
for use) and use SCCE. Paragraph (h)
would give the Regional Supervisor the
authority to require the operator to
deploy and use SCCE independent of an
operator’s determination of whether or
not to deploy and use SCCE. Requiring
immediate mobilization would prevent
operators from delaying the transit of
SCCE equipment to the well in the hope
that other source control or containment
methods will be successful. This
provision would ensure that all SCCE is
available and ready for use. Also, this
provision is being proposed to clarify
the Regional Supervisor’s discretion to
require the deployment and use of SCCE
in the event of a loss of well control or
for purposes of SCCE training and
exercises. The Regional Supervisor’s
authority is specifically addressed here
to allow the Regional Supervisor to act
in a timely manner should a loss of well
control occur.
What are the relief rig requirements for
the Arctic OCS? (§ 250.472)
As demonstrated by past loss of well
control events around the globe, in some
cases it may be necessary to drill a relief
well to permanently plug an
uncontrolled well. The SCCE is an
interim solution designed to minimize
environmental harm from well control
events, but the ultimate solution may
need to be accomplished by a relief
well. Arctic OCS exploratory drilling
operations would take place in a region
that has little or no infrastructure, that
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is subject to variable and sometimes
extreme weather, and in which
transportation systems could be
interrupted for significant periods of
time. Also, Arctic OCS exploratory
drilling operations are complicated by
the fact that they currently take place
only during the ‘‘open water season,’’ or
that period of time in the summer and
early fall when ice hazards can be
physically managed and there is no
continuous ice layer over the water.
Outside of that window, ice
encroachment may complicate or
prevent drilling and transit operations,
and for that reason it is critical to ensure
that drilling (including relief well
drilling if necessary) and other
operations affected by sea ice are
concluded before ice encroachment.
Furthermore, if there is a loss of well
control during the drilling season, it is
also important to ensure that, if a relief
rig is necessary to stop the uncontrolled
flow of oil, the relief rig is available and
able to complete all necessary
operations in as short a time as possible.
Thus, while conducting exploratory
drilling operations below the surface
casing on the Arctic OCS, it is essential
to position or designate a relief rig in a
location that would enable it to transit
to the well site, drill a relief well, plug
the original well, plug the relief well,
and demobilize from the site prior to
expected seasonal ice encroachment.
This would require the cessation of
exploratory drilling or other work below
the surface casing far enough in advance
of the expected return of seasonal ice to
allow for completion and abandonment
of a relief well.
The proposed rule would establish a
45-day maximum limit on the time
necessary to complete relief well
operations. This timeframe is necessary
to acknowledge the relative lack of
infrastructure and active operations
from which response resources could be
drawn in the region, as well as the grave
threats of a prolonged loss of well
control to the Arctic environment. If an
operator were to use a pure standby rig
(i.e., a rig that is not otherwise operating
in the Arctic), Dutch Harbor is the
nearest deep-water port where the
standby rig could be stationed. BSEE
estimates that it would take 20 days to
get the rig ready and to transit from the
nearest U.S. deep-water port (Dutch
Harbor) to the farthest well location
(Beaufort leases), 20 days to drill the
relief well, and 5 days to plug the
uncontrolled well, test it, and move off
the well site. If, on the other hand, an
operator were to use a second drilling
rig to serve as a relief rig for another
drilling rig, the time required to
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complete relief well operations could be
much shorter than 45 days because the
second rig would already be operating
in the Arctic OCS and would require
shorter transit time than a standby relief
rig staged in Dutch Harbor or at another
location.
BSEE considered imposing
prescriptive geographic limitations on
the staging of relief rigs in proximity to
exploratory drilling operations, but
chose instead to propose a performancebased requirement to provide operators
the flexibility to choose how best to
comply with the relief rig obligations.
Operators would need to demonstrate
their ability to complete relief well
operations within a maximum of 45
days, subject to BSEE’s review in the
APD process (see proposed
§ 250.470(e)). The proposed rule would
also authorize the Regional Supervisor
to direct an operator to begin drilling
the relief well.
The relief rig could be stored in
harbor, staged idle offshore, or actively
working, as long as it would be capable
of physically and contractually meeting
the proposed 45-day maximum
timeframe. However, any relief rig must
be a separate and distinct rig from the
primary drilling rig to account for the
possibility that the primary rig could be
destroyed or incapacitated during the
loss of well control incident.
Of course, an operator’s actual
timeframe to drill a relief well would be
based on consideration of the distance
between anticipated exploratory drilling
sites, the availability of adequate staging
locations for relief rigs, the length and
complexity of rig transit under Arctic
OCS Conditions, and the time necessary
to complete the requisite operations
once on-site. Thus, BSEE specifically
requests comment on whether the
maximum time limit for deploying a
relief rig and drilling a relief well
should be more or less than 45 days.
The proposed rule expressly provides
that the relief rig would only be
necessary when drilling below or
working below the surface casing (i.e.,
where contact with hydrocarbons
capable of flowing into the well could
occur). BSEE recognizes that the
proposed relief rig requirement may
effectively limit the number of days an
operator can work below the surface
casing at the end of each drilling season.
The actual length of this limitation
would depend on the operator’s plans
for staging and deploying a relief rig and
could extend up to 45 days before the
end of the drilling season (e.g., the
projected return of sea ice). During this
period, however, an operator may be
able to conduct a number of different
operations at the well site that do not
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involve work below the surface casing.
Such work can significantly advance an
exploratory drilling project and can help
an operator prepare to conduct work
below the surface casing during the
following drilling season. BSEE requests
comments on the different types of work
(above the surface casing) that could be
performed during the time period set
aside for a relief well to be drilled, if
needed, as well as the economic benefits
and costs associated with this work.
While a relief well is the most
reliable, and in some circumstances the
only available, solution to kill and
permanently plug an out-of-control
well, there could be circumstances in
which control could be regained
without intervention by a relief well.
Accordingly, BSEE also requests
comment on whether there are any
alternative technological methods, in
addition to a relief well, to kill and
permanently plug an out-of-control well
before seasonal ice encroachment.
Comments should include, where
possible, specific technological
solutions, descriptions of the conditions
under which an alternative method
could successfully kill and permanently
plug a well, and any research that
would demonstrate the effectiveness of
such an alternative.
For example, some stakeholders have
proposed that the use of subsea shut-in
devices (SIDs) located on the seafloor
could help significantly reduce the risk
of a release of hydrocarbons if the BOP
system fails. SID equipment is
specifically designed to act as a
redundant safety system and ensure the
safe and timely shut-in of a well in an
emergency. Although BSEE believes that
timely access to a relief rig is the surest
way to permanently resolve a WCD
event in the Arctic, the use of SIDs
could reduce the risk of a release of
hydrocarbons and potentially justify
giving operators more flexibility in the
staging of relief rigs.
Thus, BSEE requests comments on
alternative compliance approaches and
specifically requests data on the
performance of SIDs, including
operational issues (such as timeframes
needed to activate such alternatives). In
particular, BSEE requests comments on
appropriate staging requirements for a
relief rig assuming that an SID has been
installed at the exploration well.
Comments are also requested on the
need for an operator to have an inseason relief well drilling capability if
an SID is used at a location that is not
subject to ice scouring.
BSEE also requests information or
data comparing the relative safety and
environmental risk levels, as well as the
costs, of the equipment and procedures
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that would be required under the
proposed regulations to the risks and
costs of equipment and procedures
under any suggested alternative
approach.
In any case, BSEE’s existing
regulations allow operators the
flexibility to develop new technological
solutions and to seek approval for the
use of those solutions to fulfill their
regulatory obligations. Under 30 CFR
250.141, operators may request approval
to use alternative equipment or
procedures for any specified
requirement, provided that the operator
is able to demonstrate an equivalent or
improved level of safety and
environmental protection. This
performance-based provision is a key
part of BSEE’s regulatory program,
which is a combination of prescriptive
and performance-based requirements,
because it gives operators the ability to
comply with regulatory requirements
through a variety of methods if they can
make the necessary demonstrations to
BSEE. It also serves to encourage the
development and utilization of
alternative technologies to satisfy the
specific requirements contained in the
regulations.
What must I do to protect health, safety,
property, and the environment while
operating on the Arctic OCS? (§ 250.473)
BSEE proposes to add a new § 250.473
that would require performance-based
measures in addition to those listed in
§ 250.107 to protect health, safety,
property, and the environment during
exploratory drilling operations on the
Arctic OCS.
Paragraph (a) would require that all
equipment and materials proposed for
use in exploratory drilling operations on
the Arctic OCS be rated or de-rated for
service under conditions that could be
reasonably expected during operations.
Arctic OCS Conditions place strains on
operating equipment not experienced
elsewhere on the OCS. This necessitates
that such equipment be rated or de-rated
for use under such conditions in order
to ensure that it could operate safely
and effectively.8 For example, cranes
must be designed to withstand ice loads
that can be anticipated to build up
during Arctic OCS operations and
operational limitations of components
under extreme cold temperatures (e.g.,
reduced tensile strength) must be
understood and accounted for. Also,
capping and containment equipment
must be specifically designed to
8 It is likely that Arctic Conditions could have an
adverse impact on the performance of some
equipment and result in this equipment being
operated below the rated maximum performance
level.
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withstand the demands of regional
conditions. The Arctic Council made
similar recommendations for equipment
and materials in its 2009 report on
Arctic oil and gas operations (see Arctic
Council—Arctic Offshore Oil and Gas
Guidelines (2009)).
BSEE’s existing regulation at
§ 250.418(f) requires that operators
include in their APD ‘‘evidence that the
drilling equipment, BOP systems and
components, diverter systems, and other
associated equipment and materials are
suitable for operating’’ in areas subject
to subfreezing conditions, while
proposed § 250.473(a) would establish a
requirement for use of appropriately
rated or de-rated equipment and
materials. Operators may ensure that
proposed materials and equipment are
rated or de-rated appropriately by
referencing manufacturer specifications
and would not need to obtain
equipment or material rating by an
independent third-party rating entity.
Upon finalization of this provision,
failure to use appropriately rated or derated equipment and materials could
subject an operator or its contractor to
enforcement action by BSEE.
Paragraph (b) would require operators
to employ measures to address human
factors associated with weather
conditions that can be reasonably
expected during Arctic OCS exploratory
drilling operations. This provision is
designed to ensure safety of the
workforce and protection of the
environment by requiring operators to
account for weather conditions that
might impact decision-making and
personnel health and safety. On the
Arctic OCS, the workforce would
encounter harsh environmental
conditions, including extreme cold,
snow, ice, and freezing spray, which
could cause, among other medical
conditions, frost bite and breathing
difficulties that can impair performance
and judgment. Measures that operators
would be required to use to address
human factors include, but are not
limited to, provision of proper attire and
equipment, construction of protected
work spaces, and management of shifts.
What are the auditing requirements for
my SEMS program? (§ 250.1920)
In 2013, BSEE published an update to
Subpart S, which established additional
measures operators must take to manage
safety and to protect the environment
during their OCS operations. The
requirements under this subpart are
designed to be performance-based to
allow operators to tailor their
management systems to their particular
operations, including operations on the
Arctic OCS. For example, a hazards
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analysis for a facility on the Arctic OCS
would account for the types of hazards
expected on the Arctic OCS, like ice
floe. Similarly, Job Safety Analyses must
account for Arctic OCS Conditions, such
as ice, extreme cold, snow, and freezing
spray. BSEE would not consider an
operator’s SEMS to be effective under
§ 250.1924 if it were not specifically
tailored to the Arctic OCS Conditions
reasonably anticipated at the facility in
question.
Similarly, existing §§ 250.1914 and
250.1924 give BSEE broad authority to
require that operators on the Arctic OCS
provide BSEE with information such as
the names of contractors and the
specific scope of their duties and
timelines for performance in support of
an operator’s drilling activities. For
example, if an operator planned to use
a contractor for waste disposal,
cementing, or logging, BSEE would
expect the operator to inform BSEE of
this intent, along with any other
operations contracted out, and the
names of those contractors. Because the
existing performance-based SEMS
regulations are adequate to cover Arctic
OCS operations when properly
implemented, no major modifications
are needed to Subpart S for the Arctic
OCS. However, additional provisions
are necessary to bolster auditing
expectations for Arctic OCS exploratory
drilling operations.
This rule proposes to increase the
audit frequency and facility coverage for
intermittent Arctic OCS exploratory
drilling operations. While operators are
generally required to conduct their
SEMS audit every 3 years after their
initial audit, BSEE believes it would be
critical to perform a SEMS audit of
Arctic OCS exploratory drilling
operations and all related infrastructure
each year in which drilling is
conducted, because of the particularly
challenging conditions and high-risk
nature of those activities. This Arctic
OCS audit would require operators to
ensure that all safety systems are in
place and functional prior to
commencing or resuming, activities for
a new drilling season, as well as to
conduct the offshore portion of the audit
while drilling is under way. An operator
conducting Arctic OCS exploratory
drilling operations may not combine its
Arctic OCS facility audit(s) with audits
of its non-Arctic OCS facilities to satisfy
the facility sampling requirements
incorporated into Subpart S.
As with SEMS audits in other OCS
regions, there would be an onshore and
offshore portion. However, for Arctic
OCS exploratory drilling operations, an
operator would be required to submit a
separate audit report and corrective
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action plan (CAP) for the onshore and
offshore portions of its audit. To provide
an opportunity for BSEE to review the
onshore portion of the audit report and
CAP prior to commencement of drilling,
they must be submitted no later than
March 1st in any year in which drilling
is planned. The operator would also be
required to start and close the offshore
portion of the audit within 30 days after
first spudding of the well or entry into
an existing wellbore for any purpose
from that facility. The operator would
be required to submit the audit report
and CAP from the offshore portion of
the audit within 30 days of the close of
that portion of the audit. This is
designed to enable the auditors to
analyze offshore operations while they
are actively underway, and to ensure
that BSEE is made aware of any issues
surrounding those operations as soon as
practicable. To ensure that any critical
problems that are revealed by the audit
are addressed, BSEE would be able to
order all or part of the operations to be
shut down, if necessary.
Oil Spill Response
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Part 254—Oil-Spill Response
Requirements for Facilities Located
Seaward of the Coast Line
Definitions. (§ 254.6)
This section would include a revised
definition of Adverse weather
conditions and add new definitions of
Arctic OCS and Ice intervention
practices. These definitions are
necessary because they are important in
establishing the standard for response
capability based on environmental
conditions unique to the Arctic region.
Adverse weather conditions—The
current regulations contain a definition
for the term ‘‘adverse weather
conditions,’’ which means conditions
under which spill response activities are
difficult but nevertheless required to
proceed. The concept reflects the fact
that operators are required to pursue oil
spill response activities in all but the
most severe conditions where such
activities would become particularly
dangerous or impossible. This term is
important, especially for Arctic OCS
exploratory drilling, because it describes
the difficult conditions in which a
response is still expected to occur and
excludes conditions that present too
much of a risk to responder health and
safety for a response to proceed.
Operators are expected to consider the
delays and challenges resulting from
adverse weather when developing their
OSRP. The resulting response strategies
should reflect the right type and amount
of resources necessary to effectively
respond to a WCD scenario that would
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include adverse weather conditions on
the Arctic OCS and should factor in
anticipated disruptions or delays that
could result from operational periods
where conditions would exceed safe
operating parameters and prohibit spill
response activities from occurring.
BSEE proposes to add more specific
weather terms, i.e., extreme cold,
freezing spray, snow, and extended
periods of low light, to this definition
for clarity regarding the weather
conditions in which we expect lessees
or operators to be able to conduct
response operations on the Arctic OCS.
The addition of this terminology is
intended to ensure that operators
procure equipment that could respond
in these difficult, but feasible,
conditions and utilize spill response
technology that would be suitable for
weather conditions encountered within
the Arctic region. With this outcome in
mind, we considered establishing
quantitative descriptions specific to ice
and temperature. For example, to ensure
that identified response capabilities
would be able to operate in certain
levels of ice, one option considered was
to include 30 percent ice coverage as a
condition under which BSEE would
expect response activities to proceed.
However, BSEE concluded that using
qualitative terms would allow the
maximum flexibility in determining the
appropriate performance-based
approach necessary to respond quickly
and effectively to an operator’s WCD to
the maximum extent practicable, under
conditions reasonably anticipated
during operations. This could encourage
research and development, including
Federally funded projects, to continue
to enhance the standard response
capabilities.
Arctic OCS — For an explanation of
the definition of Arctic OCS, see the
definitions discussion at the beginning
of the Section-by-Section analysis.
Ice intervention practices—This new
term describes the equipment, vessels,
and procedures used to increase the
effectiveness of response techniques and
equipment in encountering and
mitigating the impacts of spilled oil
when sea ice is present. After oil
spreads over a broad area, the ability to
recover, burn, or disperse oil depends
on the rate at which the oil can be
identified, tracked, and encountered
(i.e., encounter rate). When ice is
present during efforts to mitigate the
impacts of spilled oil, the ice could act
as a barrier that would obscure, limit, or
prevent access to the oil, and could also
interfere with the proper operation of
response equipment. Accordingly, ice
presents unique and significant
challenges, and it is important that
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operators develop equipment and
strategies to respond to such challenges.
The other purpose of this definition is
to specifically differentiate terminology
used to describe tactics for responding
to oil in water containing sea ice from
terminology used to describe resources
and tactics employed to manage ice
during drilling operations. An operator’s
OSRP must address ice intervention
practices specifically intended to
increase the effectiveness of an oil spill
response operation. This term relates to
a new requirement for the ‘‘emergency
response action plan’’ section of OSRPs
for Arctic OCS facilities, proposed at
§ 254.80(a). Please refer to the
discussion related to that provision for
further explanation of the need for, and
importance of, this item in operators’
OSRPs.
Spill response plans for facilities
located in Alaska State waters seaward
of the coast line in the Chukchi and
Beaufort Seas. (§ 254.55)
The OSRPs for facilities in State
waters seaward of the coast line must be
submitted to BSEE for approval and
must comply with the requirements in
Subpart D. The proposed provision
would require the OSRP for any facility
conducting exploratory drilling from a
MODU in Alaska State waters seaward
of the coast line within the Beaufort or
Chukchi Seas to address the additional
requirements set forth in the new
proposed Subpart E, discussed in detail
later. BSEE has determined that the
considerations justifying the various
provisions of proposed Subpart E would
also apply to these operations.
Some requirements in Subpart E
address planning and exercises related
to the use of source control and subsea
containment equipment such as capping
stacks or containment domes. Operators
would be required to have access to and
use this equipment when conducting
exploratory drilling from a MODU on
the Arctic OCS, pursuant to proposed
regulations in Part 250, but those
conducting similar activities in State
waters are not currently subject to the
same requirements. The State of Alaska,
however, has State requirements for
source control. As such, a response plan
covering operations in State waters of
the Beaufort or Chukchi Seas must
address how the source control
procedures selected to comply with
State law would be integrated into the
planning, training, and exercise
requirements of proposed §§ 254.70(a),
254.90(a), and 254.90(c).
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Subpart E—Oil-Spill Response
Requirements for Facilities Located on
the Arctic OCS
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Purpose (§ 254.65)
This rulemaking proposes to create a
new Subpart E, in order to provide
owners and operators of exploratory
drilling facilities on the Arctic OCS with
additional requirements for oil spill
response preparedness that would
address the challenging conditions that
operators would likely encounter on the
Arctic OCS. The main purpose for the
proposed language is to establish
specific planning requirements that
would maximize oil spill response
technology application and emphasize a
complete response system that would be
designed to address the environmental
and logistical challenges inherent to
spill response activities in the Arctic
OCS region. This would include
planning for a WCD that occurs late in
the drilling season.
BSEE chose to create a new subpart
instead of incorporating the specific
requirements throughout its existing
regulatory provisions. This is similar to
the approach that was taken to address
requirements specific to State waters in
Subpart D. It is important to note that
Subpart E would add requirements for
operations on the Arctic OCS and that
all other applicable requirements in Part
254 would still apply. BSEE chose to
reserve §§ 254.66 through 254.69;
§§ 254.71 through 254.79; and §§ 254.81
through 254.89 within proposed
Subpart E.
What are the additional requirements
for facilities conducting exploratory
drilling from a MODU on the Arctic
OCS? (§ 254.70)
BSEE proposes to add § 254.70 that
would address general oil spill response
planning requirements for operators
using MODUs to conduct exploratory
drilling on the Arctic OCS. These
requirements include incorporating the
support mechanisms for capping stacks,
cap and flow systems, containment
domes, and other similar subsea and
surface devices and equipment and
vessels, required by proposed § 250.471,
into oil spill response incident action
planning. They would also require
operators to address the influence of
adverse weather conditions on
responders’ health and safety during
spill response activities. Finally, they
would require operators, prior to
resuming seasonal exploratory drilling
activities, to review their OSRPs, and
modify as necessary, to address changes
to the location or status of response
resources or the arrangements for
supporting logistical infrastructure
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arising from extended periods of time
without drilling.
Paragraph (a) would address the need
to integrate emergency well control and
containment equipment and personnel
into spill response planning to ensure
coordination during a loss of well
control event. Regaining control over
the well and containing discharged
liquids is the first line of response to a
well control incident, following failure
of primary prevention devices.
Accordingly, it is critical that those
efforts be integrated and coordinated
with the spill response efforts designed
to remove or treat oil in the water that
would proceed at the same time.
Although requirements for well control
and containment equipment operability
and safe use fall under regulations based
on the OCSLA, its integration with the
oil spill response activities is
imperative. Active information sharing
through coordinated planning efforts
will ensure that oil spill response and
source control and containment
operations would be synergistic and
mutually understood when called upon
to function together in the event of a
loss of well control.
Paragraph (b) would address
responder health and safety by ensuring
that the correct resources would be
available to protect responders from
hazards specific to the Arctic region. It
is critical for operators to address in
their OSRPs the influence of adverse
weather conditions, including extreme
cold, snow, ice, freezing spray, and
extended periods of low light, on spill
response personnel. These conditions
could impair human decision-making
and physical abilities and create risks to
personnel, operations, and the
environment. Accordingly, this
provision would require that operators
describe in their OSRPs the steps they
would take to address those factors to
ensure that their planned oil spill
response activities could be conducted
in a safe and effective manner. The
types of considerations that BSEE would
expect to be addressed include, but are
not limited to, proper attire and
equipment, protected work spaces, and
proper shift management. The objective
would be to ensure that the equipment
needed to protect human health against
adverse weather conditions would be
available immediately when a response
is required.
Paragraph (c) would address specific
challenges to maintaining preparedness
to respond to a spill when drilling is
seasonal and there are extended periods
without any risk of an oil discharge.
One of the substantial challenges
presented by operations on the Arctic
OCS is the seasonal drilling limitation
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9943
resulting from the prevalence of sea ice
on portions of the waters overlying the
Arctic OCS during all but the summer
and early fall months. This limitation
precludes active exploratory drilling
operations from MODUs on the OCS for
up to 8 months of the year, potentially
leaving associated response equipment,
materials, and personnel idle for
extended periods of time or leading to
their use in other regions of the OCS or
elsewhere.
It is important for operators to ensure
that their spill response capabilities
would not deteriorate or lose their
effectiveness due to such extended
periods of inactivity and to ensure that
they would remain capable and
adequate to conduct a quick and
effective response to an oil spill during
active exploratory drilling operations.
While BSEE encourages owners or
operators with approved OSRPs to
commit to a continuous exercise,
training, and equipment maintenance
regime that inherently builds response
skills over time, the Arctic OCS seasonal
drilling limitations challenge the
practicality of continuously maintaining
these capabilities while there is not a
risk of a discharge. To address this
challenge, BSEE would require that
owners or operators, in connection with
seasonal exploratory drilling activities,
review and submit modifications to
their OSRP as appropriate, to
demonstrate that all required resources
would be ready, before oil is handled,
stored, or transported, to respond to a
spill to the maximum extent practicable.
This OSRP review and update would
address resource allocations, changes,
and, most importantly, the reestablishment of resource readiness well
before there is a risk of discharge. BSEE
would review and approve proposed
OSRPs for resource maintenance during
extended periods without drilling
activity through established OSRP
approval, modification, revision, and
update processes described in §§ 254.2,
254.30, and 254.53, and the proposed
update described in this section.
What additional information must I
include in the ‘‘Emergency response
action plan’’ section for facilities
conducting exploratory drilling from a
MODU on the Arctic OCS? (§ 254.80)
BSEE also proposes to create a new
§ 254.80 that would focus on additional
information requirements for the
emergency response action plan section
of an OSRP when the operator proposes
to conduct exploratory drilling
operations from a MODU on the Arctic
OCS. The additional requirements
would include specifics regarding ice
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intervention practices, staging
considerations, and tracking abilities.
Sea ice could reduce the effectiveness
of spill response techniques by limiting
access to spilled oil and decreasing oil
encounter rates. Therefore, in paragraph
(a), BSEE would require Arctic OCS
exploratory drilling operators to
describe their ice intervention practices
and how they would improve the
effectiveness of spill response
equipment and response strategies in
the presence of sea ice. Increasing oil
encounter rates when sea ice is present
maximizes efficiency in removing or
mitigating the adverse impacts from oil
in the water as quickly and effectively
as possible. The necessary practices and
equipment would work to mitigate the
impacts of ice on response operations
and extend the period in which oil spill
response activities could occur. They
would also ensure that appropriate ice
management vessels would be included
when determining equipment
requirements that would enhance all
response options and strategies
included in the plan.
Operators must ensure that they
would have the capability to initiate a
rapid response to the site of an offshore
oil spill, as well as to sustain and, when
necessary, repair response equipment
on-site without having to rely on shorebased assets that could become
inaccessible due to weather conditions
or other factors. Due to the remote
locations where Arctic OCS exploratory
drilling operations would occur, and the
limited infrastructure and logistical
support capabilities in the coastal
communities, operators would need to
consider strategic staging locations and
support mechanisms for effectively
deploying and resupplying oil spill
response resources. For the Arctic OCS,
initial response capabilities, in many
instances, would need to be based
offshore to effectively meet the
requirements in Part 254. Pursuant to
paragraph (b)(1), operators would be
required to describe how they would
maintain assets in close proximity to
exploratory drilling operations to ensure
that adequate response times would be
achievable and response operations
would be sustainable. The weather
conditions that are common to the area
(e.g., dense fog, high sea states) often
preclude access to the area by small
vessels and aircraft for days at a time.
The ability to mount and maintain an
expeditious response once a release
occurs would be negatively impacted if
response assets or supporting materials
were significantly delayed from arriving
at the spill site due to inclement
weather. Accordingly, operators must
establish an offshore resource
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management system to ensure that
vessels and equipment would be readily
available, along with sufficient
personnel and berthing, to carry out
response activities.
The limited support and response
capabilities and capacities that exist in
most Alaska coastal communities
mandate that operators provide for
nearly all aspects of an oil spill response
on the Arctic OCS. Paragraph (b)(2)
would require operators to identify how
they intend to ensure an immediate and
uninterrupted flow of supplies,
response equipment, personnel, and
shore-based support services to sustain
the response activities until terminated
by the Unified Command.9 The
components of the logistics supply
chain include, but are not limited to:
Personnel and equipment transport
services; airfields and types of aircraft
that can be supported; capabilities to
mobilize supplies (e.g., response
equipment, fuel, food, fresh water) and
personnel to the response sites; onshore
staging areas, storage areas that may be
used en route to staging areas, and camp
facilities to support response personnel
conducting offshore, nearshore and
shoreline response; and management of
recovered fluid and contaminated debris
and response materials (e.g., oiled
sorbents), as well as waste streams
generated at offshore and on-shore
support facilities (e.g., sewage, food, and
medical). Operators must also plan to
implement mitigation measures to
reduce the impacts that surged
personnel, equipment, and increased
activity would have on communities
where staging areas, camp facilities, and
waste handling sites are established.
In paragraph (c), BSEE proposes to
require operators to describe how they
would maintain an effective tracking
and management system that is able to
locate in real time all response
equipment and personnel conducting
response activities, or transiting to and
from the response site(s), and to
maintain a current picture of resources
entering and exiting staging areas and
the operational status of those resources.
This system would be essential to
provide the Unified Command with
information necessary to ensure that
sufficient personnel and equipment
would be available to meet the response
needs.
Part 254 requires operators to describe
all equipment they plan to use to
respond quickly and effectively to an oil
spill to the maximum extent practicable.
9 The Unified Command is a response construct
under the incident command system headed by
Federal authorities and coordinated with the State
and other parties.
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For oil spill response planning, BSEE
would not consider it adequate
preparedness for an operator to assume
that the Federal On-Scene Coordinator
would call upon assets under the
control of other entities during a
response. As previously mentioned in
the Part 550 discussion, it is important
to note that an effective and immediate
removal or mitigation of a discharge
must be achieved to the maximum
extent practicable by private sector
efforts.
What are the additional requirements
for exercises of your response personnel
and equipment for facilities conducting
exploratory drilling from a MODU on
the Arctic OCS? (§ 254.90)
BSEE proposes to create a new
§ 254.90 that would require operators to
incorporate the additional requirements
contained within proposed §§ 254.70
and 254.80 into their oil spill response
training and exercise activities; would
require operators to provide notice of
the commencement of covered
operations; and would clarify the
authority of the Regional Supervisor to
conduct exercises, prior to and during
exploratory drilling operations, to test
response preparedness. These
requirements are all essential to
ensuring and verifying an operator’s
readiness to conduct response activities
on the Arctic OCS.
As described previously with respect
to proposed § 254.70(a), it is essential
that the relevant support mechanisms
(personnel, materials, and vessels) for
capping stacks, cap and flow systems,
and containment domes, and other
similar subsea and surface devices and
equipment and vessels, be integrated
and coordinated with the spill response
planning and activities that would take
place alongside them, and that those
arrangements are suitable for
deployment on the Arctic OCS.
Accordingly, proposed § 254.90(a)
would require that operators incorporate
the required personnel and equipment
into spill-response training and
exercises to ensure the necessary and
appropriate level of coordination
between source control and subsea
containment activities and spill
response activities.
Similarly, to ensure that these training
and exercise activities would accurately
reflect and test the full scope of
response capabilities necessary for
Arctic OCS operations, proposed
§ 254.90(a) would also require that
operators incorporate other proposed
response plan features from proposed
§§ 254.70 and 254.80 into those
activities. As outlined in proposed
§ 254.90(c), the Regional Supervisor
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may direct operators to deploy response
resources, as part of announced or
unannounced exercises, to verify an
operator’s preparedness for responding
to a spill on the Arctic OCS. These
exercises might include the deployment
of capping stacks, cap and flow systems,
containment domes, or other supporting
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equipment in order to test their
integration and coordination with other
oil spill response activities. However,
SCCE is not required to be deployed
under the annual and triennial
equipment deployment requirements
outlined in § 254.42(b)(2).
Finally, proposed § 254.90(b) would
require operators planning to conduct
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9945
exploratory drilling from a MODU on
the Arctic OCS to provide 60-days’
notice before handling, storing, or
transporting oil to give BSEE adequate
opportunity to verify that the operator’s
personnel and equipment are in
compliance with existing regulations.
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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules
D. Arctic Exploratory Drilling Process
Flowchart
BILLING CODE 4310–VH–; 4310–MR–P
•:• Integrated 0Qerations Plan (550.204]
•!• -- Indicates proposed new provisions; all
,
existing applicable regulations continue to
\11
apply unless otherwise noted; all citations
.
ExQioration Plan
•
550.211-228 requirements
are to Title 30 of the CFR
OSRP Submitted for AQQroval
In compliance with Part 254;
•!• Including new Subpart E
•!• Arctic Suitability [550.220(c)(l)]
•!• Ice and Weather [550.220(c)(2)]
•:• SCCE, Relief Rig [550.220(c)(3)-(4)J
•!• Resource Sharing [550.220(c)(5)]
"
r-"""'
..I
\11
"
"0
OSRP Approval
EPApproval
::>
::>
:r
I
$>
~
'
iii"
SEMS in place [Part 250, SubpartS]
.
BOEM- BSEE
Arctic OCS
Exploration
Planning,
Permitting, and
Operations
Flowchart
"0
"'
APD Submission
250.410-418 requirements
•!• Arctic Suitability [250.470(a)]
•!• Transition Operations [250.470(b)]
•!• Objectives, Timelines, and
"
~
•!•
SEMS Onshore Audit
(Report and CAP by March 1)
[250.1920(b)-(e)]
5'
$>
'c."
::>
'!?
"'
"0
~
~
c;·
'
Contingency Plans [250.470(c)]
•!• Weather and Ice [250.470(d)]
•!• Relief rig plans [250.470(e)]
•!• SCCE Capabilities [250.470(f)]
•!• API RP2N description [250.470(g)]
•!• Notification of RS (60 days before
::>
..__
drilling) [254.90(b)]
I
~
APD Approval
I
"'
Commence EKQioration Drilling
•!• Start with well cellar (or
f<~
.
Drilling or Working Below Surface
•!•
•!•
•!•
•!•
•!•
•!•
•!•
Casing
•:•
equivalent) if ice scour [250.402]
t
•!• SCCE Staged [250.471(a)]
•!• Relief Rig Staged [250.472]
·~
•!•
•!•
•!•
•!•
I
Drilling 0Qerations Reguirements:
Compliance with all generally applicable law and regs
Properly rated/de-rated equipment and materials [250.473(a)]
Address human factors in weather conditions [250.473(b)]
Offshore Portion of SEMS Audit with report and CAP [250.1920(b)-(e)]
Capture of Mud and Cuttings (as required) [250.300(b)]
Real-time operational monitoring [250.452]
Weather and Ice tracking and forecasting [250.470(d)]
Reporting of ice, ice management, and kicks [250.188(c)]
Monthly Capping Stack stump tests [250.471(b)]
7-day BOP pressure testing [250.447(b)]
Personnel training [250.470(f)(5); 254.70(a); 254.90(a)]
Drills and exercises (SCCE and OSR) [250.471(d) & (g); 254.90(a) & (c)]
Protection of well and equipment upon TA (250.402(c)]
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I
J,
Offseason
iE"""""""""""-
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~
-........
Sfmt 4702
~
..~
5'
;-
BILLING CODE 4310–VH–; 4310–MR–C
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0
'tl
0
Conclusion of on-site operations
(including abandonment)
•!• Transition per APD (250.470(b)]
[250.452(b); 250.471(e) & (f)]
20:32 Feb 23, 2015
~
5'
O'Q
"
•!• Spill response readiness and
maintenancel[~&.70(c)]
•!• Maintenance of data and records
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--
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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules
V. Conclusion
Overall, the proposed rule would
further the Nation’s energy goals in
prudently exploring frontier areas, such
as those in the Arctic OCS, by
establishing operating models and
requirements tailored specifically to the
extreme, unpredictable, and rapidly
changing conditions that exist in the
Arctic region. The proposed regulations
reflect the need for earlier and more
comprehensive planning of operations,
particularly with respect to emergency
response and safety systems. The
proposed Arctic OCS exploratory
drilling rule would institutionalize a
proactive approach to safety.
Vulnerabilities would be identified in
the planning phase and corrections
would be made to reduce the likelihood
of an incident occurring. The proposed
rule would also ensure that those plans
would be carried forward and executed
in a manner that would ensure safety
and environmental protection under the
challenges presented to operations by
Arctic OCS Conditions.
Finally, the proposed rule would
integrate emergency response,
comprehensive operational and safety
planning, contractor oversight, and
upfront mutual aid agreements. The
proposed combination of prescriptive
and performance-based requirements
would precipitate robust consideration
of how safe exploration of the Arctic
region is to be achieved.
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
VI. Procedural Matters
A. Regulatory Planning and Review
(E.O. 12866 and E.O. 13563)
Changes to Federal regulations must
undergo several types of economic
analyses. First, E.O. 12866 and E.O.
13563 direct agencies to assess the costs
and benefits of available regulatory
alternatives and, if regulation is
necessary, to select a regulatory
approach that maximizes net benefits
(accounting for the potential economic,
environmental, public health, and safety
effects). E.O. 13563 emphasizes the
importance of quantifying both costs
and benefits, reducing costs,
harmonizing rules, and promoting
flexibility. Under E.O. 12866, an agency
must determine whether a regulatory
action is significant and, thus, subject to
the requirements of the E.O. and OMB
review. Section 3(f) of E.O. 12866
defines a ‘‘significant regulatory action’’
as any rule that:
1. Has an annual effect on the
economy of $100 million or more, or
adversely affects in a material way the
economy, a sector of the economy,
productivity, competition, jobs, the
environment, public health or safety, or
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20:32 Feb 23, 2015
Jkt 235001
State, local, or tribal governments or
communities (also referred to as
‘‘economically significant’’);
2. Creates serious inconsistency or
otherwise interferes with an action
taken or planned by another agency;
3. Materially alters the budgetary
impacts of entitlement grants, user fees,
loan programs, or the rights and
obligations of recipients thereof; or
4. Raises novel legal or policy issues
arising out of legal mandates, the
President’s priorities, or the principles
set forth in E.O. 12866.
B. E.O. 12866
E.O. 12866 provides that OMB’s
Office of Information and Regulatory
Affairs will review all significant rules.
Pursuant to the procedures established
to implement § 6 of E.O. 12866, OMB
has determined that this proposed rule
is significant because the estimated
annual costs or benefits exceed $100
million in at least one year of the
analysis period. The following
discussion summarizes the economic
analysis; a more detailed Initial RIA can
be found in the regulatory docket for
this proposed rule at
www.regulations.gov (in the Search box,
use BSEE–2013–0011). BOEM and BSEE
request comments on the assumptions
used in the Initial RIA and on other
possible alternatives to consider,
including alternatives to the specific
provisions contained in the proposed
rule.
1. Need for Regulation
This proposed rule seeks to enhance
requirements for safe, effective, and
responsible Arctic OCS oil and gas
activities. Although there is currently a
comprehensive OCS oil and gas
regulatory program, DOI engagement
with partners and stakeholders,
including environmental groups and
Alaska Natives, reveals the need for new
and enhanced regulatory measures for
Arctic OCS exploratory drilling. The
current rulemaking focuses primarily on
reasonably foreseeable Arctic OCS
exploratory drilling activities that use
MODUs, and on related operations
during the Arctic open-water drilling
season (generally late June to early
November). After the proposed
requirements for exploratory drilling are
finalized and applied to those activities,
DOI will be able to assess whether it
should apply similar requirements to
development drilling.
This proposed rule builds on input
received from partners and
stakeholders, key components of Shell’s
2012 Arctic exploratory drilling
program, and the additional measures
BOEM and BSEE required Shell to
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9947
perform under existing regulatory
authorities. After considering the input
received and our direct experience from
Shell’s 2012 Arctic operations, BOEM
and BSEE have concluded that
additional exploratory drilling
regulations would enhance and clarify
existing regulations and would be
appropriate as a part of the Arctic OCS
oil and gas regulatory framework.
The proposed rule would further the
Nation’s interest in exploring frontier
areas, such as those in the Arctic OCS
region, safely and responsibly, and
would establish specific operating
models and requirements that account
for both the extreme, changing
conditions that exist on the Arctic OCS
and Alaska Natives’ cultural traditions
and need to access subsistence
resources. The proposed regulations
would require comprehensive planning
of operations, especially for emergency
response and safety systems. The
proposed rule would seek to
institutionalize a proactive approach to
offshore safety. A goal of the proposed
rule is to identify potential
vulnerabilities early in the planning
process so that corrections can be made
to decrease the potential of an incident
occurring. The requirements in the
proposed rule also are designed to
ensure that those plans would be
executed in a safe and environmentally
protective manner despite the
challenges the Arctic OCS presents.
In particular, this proposed rule
would address several important
objectives, including ensuring that
operators:
i. Design and conduct exploration
programs in a manner suitable for Arctic
OCS conditions;
ii. Develop an IOP that would address
all phases of their proposed Arctic OCS
exploration program and submit the IOP
to BOEM at least 90 days in advance of
filing an EP;
iii. Have access to and the ability to
promptly deploy SCCE while drilling
below or working below the surface
casing;
iv. Have access to a separate relief rig
located so that it could timely drill a
relief well, in the event of a loss of well
control, under the conditions expected
at the site;
v. Have the capability to predict,
track, report, and respond to ice
conditions and adverse weather events;
vi. Effectively manage and oversee
contractors; and
vii. Develop and implement OSRPs
designed and executed in a manner
suitable for the unique Arctic OCS
operating environment and have the
necessary equipment, training, and
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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules
personnel for oil spill response on the
Arctic OCS.
The following provisions of the
proposed rule are expected to result in
additional costs, above the baseline, to
the affected industry:
i. Additional Incident reporting
requirements;
ii. Additional pollution prevention
requirements;
iii. Additional requirements for
securing wells;
iv. Additional BOP pressure testing
requirements;
v. Real-time monitoring requirements;
vi. Additional information
requirements for APDs;
vii. Incorporation of proposed draft
API RP 2N, Third Edition;
viii. Additional SCCE requirements;
ix. Relief rig requirements;
x. Additional auditing requirements;
xi. Real-time location tracking
requirements;
xii. IOP requirements;
xiii. Additional requirements for EPs;
and
xiv. Industry familiarization with the
rule.
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2. Alternatives
As explained in the Initial RIA, BOEM
and BSEE have considered three
alternatives for dealing with the safety
and environmental concerns that
exploratory drilling activities on the
Arctic OCS have raised:
i. Promulgate the rule changes
described in this proposed rule; or
ii. Promulgate the rule changes
described in the proposed rule without
including the 7-day BOP pressure
testing requirement for Arctic OCS
exploratory drilling operations (in
§ 250.447 of the proposed rule); or
iii. Take no regulatory action and
continue to rely on existing oil and gas
regulations, industry standards, and
operator prudence.
BSEE has decided not to issue a
proposed rule without the 7-day BOP
testing requirement. The additional
testing requirement would help ensure
that BOPs deployed in the Arctic OCS
function properly and reduce the risk of
blowouts. BSEE has determined that the
total cost to industry of including this
requirement is approximately $135.1
million over the 10-year analysis period
(with 7 percent discounting). The cost
summary tables below present the total
costs of the proposed rule with and
without the additional BOP pressure
testing requirements.
BOEM and BSEE also have decided to
move forward with this proposed rule,
in lieu of taking no regulatory action,
because relying on the regulatory status
quo would not address the safety and
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20:32 Feb 23, 2015
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environmental concerns in the Arctic
region that partners and stakeholders
have raised, and thus would not achieve
the objectives of this proposed rule. In
addition, the proposed rule would
confer additional protections on the
environment and Alaska Native cultural
activities.
3. Economic Analysis
BOEM and BSEE evaluated the
potential cost impacts of the proposed
rule against the baseline. The analysis
reflects only the activities and capital
investments the proposed rule requires
that represent a change from the
baseline. The analysis covers 10 years
(2015 through 2024) to ensure it
captures important benefits and costs
that could result from the proposed
rule.10 When summarizing the costs and
benefits, we present the estimated
annual effects and the 10-year
discounted totals using discount rates of
3 and 7 percent, per OMB Circular A–
4, ‘‘Regulatory Analysis.’’ BOEM and
BSEE welcome comments on this
analysis, including comments on the
assumptions, the baseline, the methods
used, and on the potential sources of
data or information on the costs and
potential benefits of this proposed rule.
i. Assumptions
The baseline refers to existing
regulatory requirements, industry
standards, and operator prudence.
According to OMB’s Circular A–4, the
baseline should be ‘‘the best assessment
of the way the world would look absent
the proposed action.’’ Thus, the
economic analysis excluded activities or
capital investments that existing
regulations require as well as impacts
resulting from the incorporation of
industry standards with which industry
voluntarily complies. The baseline also
includes only costs associated with
requirements that BOEM or BSEE have
previously routinely imposed in other
regions under their existing regulatory
authorities, but does not include the
costs described as follows:
a. Relief Rig Capital Costs: The
proposed rule requires Arctic OCS
operators to have access to a separate
relief rig located such that it could
timely drill a relief well if a loss of well
10 As explained in the Initial RIA, we used a 10year period for this analysis because of the
uncertainty associated with predicting industry’s
activities and the advancement of technical
capabilities. For example, the costs associated with
a particular new technology may decrease as the
technology is adopted more broadly over time. In
other cases, an existing technology may be replaced
by a lower-cost alternative. Extrapolating results
beyond this 10-year time frame would produce
more ambiguous results and, therefore, be
disadvantageous in determining actual costs and
benefits likely to result from this proposed rule.
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control were to occur and drilling a
relief well becomes necessary. Although
a relief rig was required by DOI during
Shell’s 2012 Arctic operations, and
although BOEM and BSEE anticipate
that we would exercise our existing
authorities to require a relief rig for any
future exploratory drilling on the Arctic
OCS, we chose not to include the capital
costs associated with staging a relief rig
that may not be conducting exploratory
drilling (i.e., a standby rig) in the
baseline.11 Instead, we conservatively
chose to include such costs as part of
the costs of the rule, in the detailed
economic analysis contained in the
Initial RIA. These costs are estimated at
$276 million per year per standby rig.
Based on EPs and other information,
however, BOEM and BSEE believe that,
in the future operators would likely
designate a second operating rig to be a
relief rig (instead of staging a dedicated
standby relief rig) because, over time,
the increased presence of multiple
operating rigs on the Arctic OCS would
make it easier for one operating rig to be
designated as a relief rig for another
operating rig. Nonetheless, because an
operator may choose to deploy a
dedicated standby relief rig, the
economic analysis conservatively
includes the estimated costs for a
standby rig for 2015 and 2016.
In addition, costs associated with
documenting a relief rig plan are not
included in the baseline for the analysis
and are included in the economic
analysis.
b. Relief Rig Activity Costs: The
proposed rule would establish a 45-day
maximum limit on the time necessary to
complete the relief well operations
activities. This provision effectively
would require the cessation of
exploratory drilling or other work below
the surface casing far enough in advance
of the expected return of seasonal ice to
allow for completion and abandonment
of a relief well. BOEM and BSEE
approved plans for Shell’s 2012 Arctic
operations required drilling operations
in zones that can support the flow of
liquid hydrocarbons in measurable
quantities into the well to be concluded
38 days before November 1, based on
satellite imagery showing the 5-year
historical average of earliest
encroachment of sea ice over the
applicant’s drill site and the estimated
time required to drill a relief well. Thus,
11 Although Shell included a relief rig
requirement in its Beaufort Sea and Chukchi Sea
EPs for the 2012 season (which BOEM approved
and which were subsequently incorporated in
Shell’s APDs, as approved by BSEE), BOEM would
have required that a relief rig be included in Shell’s
EPs under the authority currently found in 30 CFR
550.213 and 550.220 in any event.
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Federal Register / Vol. 80, No. 36 / Tuesday, February 24, 2015 / Proposed Rules
the baseline for this analysis includes
this 38-day requirement from 2012.
Accordingly, the potential costs of the
proposed 45-day maximum timeframe
include only the costs of the additional
7 days (45 days minus 38 days) not
included in the baseline, during which
drilling or work below the surface
casing could not take place.
We recognize that the requirement to
have the capability to drill a relief well
to permanently kill an out-of-control
well may lead to a reduction in the
number of days during which operators
can perform work below the surface
casing during the drilling season. There
will be costs and benefits associated
with this requirement. Those costs
(including ‘‘opportunity costs’’) may
also include costs resulting from a
reduction in the number of wells that
can be drilled during the term of the
lease under which the operator is
conducting exploratory drilling
operations.
The Initial RIA for the proposed rule
discusses the challenges associated with
estimating opportunity costs. Because
the Arctic OCS is a frontier area for
drilling operations, there are very few
data points that would provide the basis
for accurate estimates. Any attempt to
calculate opportunity costs would have
to take into account the significant
number of uncertainties associated with
exploratory drilling, the nature of the
economic benefits sought to be achieved
by such operations (e.g. booking
reserves), and a variety of other factors.
These factors will often depend upon
the decisions an operator makes on how
to conduct drilling operations during
each drilling season and the nature of
the opportunities for other productive
use of the assets.
Data available to BOEM and BSEE
indicate that the estimated daily
operating cost of a drilling rig located in
the Arctic OCS is approximately $2
million. This estimate includes all of the
costs associated with operating a rig
(e.g., including the costs of the rig crew).
This figure is based upon an analysis of
the daily costs of rigs currently
operating in the Gulf of Mexico,
adjusted significantly upward to
account for the harsh operating
conditions in the Arctic. The actual
operating costs for a rig operating in the
Arctic OCS will likely vary greatly from
season to season. Industry data
presented in the course of this
rulemaking indicated that the fixed
costs of drilling in the Arctic for one
season are $1.2 billion, which,
amortized over an entire 100-day season
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of drilling, is equivalent to $12 million
per day in sunk costs.12
Any calculation of opportunity costs
should include an estimated return on
investment. Such a calculation could be
based on the OMB Circular A–4
estimate of the average before-tax rate of
return to private capital in the U.S.
economy (7 percent) or could be based
on the industry stated average return on
capital (10 percent).
Any calculation of opportunity costs
should also estimate the number of days
per season that the operator could not
conduct work below the surface casing.
While the proposed rule would impose
a maximum period of 45-days for a
relief rig to deploy and complete a relief
well and, thus, a maximum of 45-days
during which work below the surface
casing would not occur, the actual
number of days during which an
operator would not be able to conduct
drilling or other work below the surface
casing is subject to a number of
variables. As discussed previously, we
estimate that it would take 20 days to
prepare and transport a rig from the
nearest U.S. deep water port (Dutch
Harbor) to the farther well location
(Beaufort leases), 20 days to drill the
relief well, and five days to plug the
uncontrolled well, test it, and move off
the well site. Further, the actual time
needed for completing a relief well
operation would vary depending on a
number of factors. For example, the
estimated actual time needed would
depend on how an operator proposes to
stage a relief rig; e.g., if it chooses to
deploy a dedicated standby relief rig or
to designate a second operating rig as a
relief rig. In the latter case, a relief rig
operating in the near vicinity of the
primary rig, as proposed by Shell in its
revised Exploration Plan for 2015,13
may be able to reach the site of a
blowout and complete a relief well in as
little as 25 days, assuming no transit
time for the rig.
Moreover, other work, which will
likely have significant economic benefit,
may continue under the proposed rule
during the period that work below the
surface casing is not allowed, providing
economic benefits from other activities
that could be conducted during this
period (for example, in 2012, Shell
drilled top holes during the period it
12 During a meeting conducted with OMB
pursuant to E.O. 12866, Shell stated that its total
costs for a 100-day drilling season were $1.5 billion
and that 80% of those costs ($1.2 billion) were
‘‘sunk.’’ Dividing these costs by 100 (the assumed
length of the drilling season) yields an estimate of
$12 million per day. These costs have not been
independently validated by BOEM and BSEE, and
it is not known if the industry figure provided
already included the expected return on capital.
13 http://www.boem.gov/EP–PUBLIC–VERSION/.
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9949
was not allowed to drill into
hydrocarbon bearing zones). If the
alternative work was of similar
economic value, there would be no
opportunity cost. However, it is likely
the alternative work would have a lesser
value than the forgone work, and thus
only partially offset the opportunity
cost.
The Initial RIA assumes that, during
10 years of exploratory drilling
operations, primary rigs (up to four per
season during 2018–2024) will conduct
a total of 32 drilling campaigns. During
those drilling campaigns, costs
associated with each rig will be highly
variable. Current estimates of these costs
range from $ 2 million to $12 million
per day. The breadth of this range,
combined with the number of
significant additional variables (number
of days affected; rate of return), makes
it difficult to estimate a range of annual
opportunity costs. Additional data
related to operating costs, forecasted
positioning of relief rigs, the economic
effect of operating two rigs in theater
during the same season, and other
significant variables may provide the
basis for meaningful estimates of annual
opportunity costs associated with the
requirement that a relief rig be able to
deploy and complete a relief well
within 45 days of the end of the drilling
season. We encourage comments on
such estimated costs, as well as benefits,
with supporting data, including data on
the uses to which a primary rig could be
put during the time it is not working
below the surface casing. Any such
estimates should, if appropriate, include
estimated return on capital that would
be forgone as a result of these
requirements.
c. BOP Pressure Testing
Requirements: We do not include the 7day BOP pressure-testing requirements
in the baseline for the analysis because,
although Shell agreed to this
requirement as a condition of its 2012
operations, Shell ultimately did not
conduct these BOP pressure tests during
that operating season. Thus, we
conservatively include the costs
associated with the increased BOP
pressure testing requirements in the
analysis of the costs for Alternative 1.
Based on BOEM’s and BSEE’s
knowledge of operators engaged in, or
likely to be engaged in, Arctic OCS
exploration activities, we also made
several assumptions about the number
of operators, rigs, and wells operating
on the Arctic OCS over the 10-year
analysis period. We based all
assumptions on our experience with
recent and expected industry practices
for operators on the Arctic OCS,
including information submitted to
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BOEM and BSEE by lessees and
operators and other available
information related to planned or
potential industry exploratory activities
Inputs
for the analysis period. Exhibit 1
presents these assumptions. We seek
comments on the reasonableness of
these assumptions.
2015
Operators .........................................................
Primary rigs ......................................................
Standby relief rig 1 ............................................
Exploratory wells drilled each year ..................
Applications for permit to drill ..........................
Exploration plans ..............................................
Integrated operations plans .............................
Oil spill response plans ....................................
2016
1
2
1
2
2
1
2
2
2017
1
2
1
4
4
2
2
2
2018
1
2
0
4
4
2
2
2
Exhibit 1. Assumptions About the
Affected Population of Operators and
Drilling Operations
2019
3
4
0
4
4
2
2
2
2020
3
4
0
4
4
2
2
2
2021
3
4
0
6
6
2
2
2
2022
3
4
0
6
6
2
2
2
2023
3
4
0
6
6
2
2
2
2024
3
4
0
6
6
2
2
2
3
4
0
6
6
2
2
2
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
1 Standby relief rigs are rigs that are not conducting exploratory drilling and are assumed to incur different costs than relief rigs that are conducting exploratory drilling (i.e., ‘‘primary rigs’’).
Other data inputs and assumptions
common to many of the calculations
include the following:
d. SCCE and Resource Sharing: The
proposed rule requires operators to have
access to, and the ability to promptly
deploy, SCCE while conducting Arctic
OCS exploratory drilling or work below
the surface casing. In the cost analysis,
we assume that the operator conducting
exploratory drilling beginning in 2015
already owns the required SCCE. We
also assume that the operator with two
primary rigs in 2017 will use one set of
SCCE to satisfy the SCCE requirements
for both of its rigs. Finally, we assume
that, of the two operators entering in
2018, one will purchase the SCCE and
the other will select the least-cost means
to comply with the proposed rule and
enter into resource sharing with an
operator who has already purchased the
SCCE.
Because the industry does not
currently engage in resource sharing on
the Arctic OCS, BOEM and BSEE have
no details on how the process would be
conducted and whether or to what
degree, for example, an operator would
charge for access to equipment. The
SCCE resource-sharing assumptions
represent the most likely scenario based
on BSEE’s knowledge of the industry.
BOEM and BSEE also considered a lowcost scenario and a high-cost scenario
that vary the assumptions for resource
sharing and purchase of SCCE by
operators. The Initial RIA for the
proposed rule discusses the costs
associated with these scenarios.
e. Daily Rig Operating Costs: Based on
BSEE estimates and cost estimation
methodologies from the BOEM Case
Study, we assume that rigs on the Arctic
OCS have a daily operating cost of $2
million. For the purposes of the
analysis, we assume that the daily rig
operating costs remain constant over the
10-year analysis period. We also assume
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that the drilling season on the Arctic
OCS lasts 138 days.14
f. BSEE Burden to Review Paperwork
Submissions: For each paperwork
submission, we assume that for every
hour that industry devotes to compile
and submit information, BSEE will need
one half hour to review the
submission.15
g. Wage Rates and Loaded Wage
Factors: For this analysis, we obtained
median industry wage rates from the
Bureau of Labor Statistics May 2012
Occupational Employment Statistics for
the industry labor categories. We also
obtained wage rates for BOEM and BSEE
personnel from the Office of Personnel
Management 2012 General Schedule for
the government labor categories. To
account for employee benefits, we
multiplied the hourly wage rates by
appropriate loaded wage factors to
generate hourly compensation rates. The
Initial RIA for the proposed rule
includes details on wage rates and
loaded wage factors used in the
analysis.
4. Costs
The analysis presented in the Initial
RIA describes the potential costs of the
proposed rule compared to the baseline.
Exhibit 2, which follows, summarizes
these proposed requirements and their
associated costs to industry and
government. Please see the Initial RIA
for details on the exact assumptions and
calculations.
i. Additional Incident Reporting
Requirements: Operators would be
required to provide an immediate oral
report to the BSEE onsite inspector, if
14 We assume a 138-day drilling season for all
purposes other than the prior discussion of
opportunity costs, which uses a 100-day drilling
season as assumed in the industry presentation to
OMB. See n.13.
15 The submissions to BOEM under Part 550 of
the proposed rule do not follow this standard
review estimate because these submissions would
require a more time-intensive review by several
employees.
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one is present, or to the Regional
Supervisor of any sea ice movement or
condition that has the potential to affect
operations or trigger ice management
activities, the start and termination of
such activities, and any ‘‘kicks’’ or
operational issues that are unexpected
and could result in the loss of well
control. Operators also would be
required to submit a follow-up written
report regarding any ice management
activities undertaken within 24 hours,
following completion of those activities.
ii. Pollution Prevention Requirements:
Operators would be required to capture
all petroleum-based mud and cuttings
from operations that use petroleumbased mud. In addition, these
subparagraphs clarify the Regional
Supervisor’s discretionary authority to
require operators to capture all waterbased muds and associated cuttings
from Arctic OCS exploratory drilling
operations after completion of the hole
for the conductor casing to prevent their
discharge into the marine environment.
iii. Additional Requirements for
Securing Wells: Operators that move a
drilling rig off a well prior to
completion or permanent abandonment
would be required to ensure that any
equipment left on, near, or in a well
bore that has penetrated below the
surface casing is positioned to protect
the well head and prevent or minimize
the likelihood of compromising the
down-hole integrity of the well or well
plug effectiveness. Additionally, in
areas of ice scour, operators would be
required to use a well cellar or an
equivalent means of minimizing the risk
of damage to the wellhead.
iv. Additional BOP Pressure Testing
Requirements: Operators conducting
Arctic OCS exploratory drilling
operations would be required to begin
testing the BOP system before midnight
on the seventh day following the
conclusion of the previous test. This
proposed requirement would represent
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an increased testing frequency
(compared to the current requirement
for testing every 14 days).
v. Real-time Monitoring
Requirements: These proposed new
real-time monitoring requirements for
Arctic OCS exploratory drilling
operations include real-time data
gathering and monitoring capability for
data on the BOP control system, the
fluid handling systems on the rig, and
the well’s downhole conditions. They
also include onshore data transmission,
monitoring, storage, and notification
and availability of data to BSEE.
vi. Additional Information
Requirements for APDs: This provision
would require operators to submit
Arctic OCS-specific information with
APDs for Arctic OCS exploratory
drilling. This includes a detailed
description of how the drilling unit,
equipment, and materials will be
prepared for service in Arctic OCS
Conditions. Operators would be
required to submit a detailed
description of all operations necessary
in Arctic OCS Conditions to transition
the rig from being underway to
commencing drilling operations and
from concluding drilling operations to
being underway, as well as any
anticipated repair and maintenance
plans for the drilling unit and
equipment. Operators would also be
required to submit well-specific drilling
objectives, timelines, and updated
contingency plans for temporary
abandonment of the well. Finally,
operators would be required to submit
information on weather and ice
forecasting capability for all phases of
drilling operations.
vii. Incorporation of Proposed Draft
API RP 2N, Third Edition: This
provision would require operators to
submit a detailed description of how the
relevant aspects of proposed draft API
RP 2N, Third Edition, ‘‘Planning,
Designing, and Constructing Structures
and Pipelines for Arctic Conditions,’’
are addressed in the planning of
exploratory drilling operations. API RP
2N is a voluntary consensus standard
that addresses the unique Arctic
conditions that affect the planning,
design, and construction of systems
used in Arctic and sub-Arctic
environments.
viii. Additional SCCE Requirements:
There are several proposed SCCE
requirements, including equipment,
stump testing, well design change
information requirements, test and
exercise, records maintenance, and
documentation. Because the industry
does not currently engage in resource
sharing on the Arctic OCS, BOEM and
BSEE do not have details on how that
process would be conducted and
whether, for example, an operator
would charge for access to equipment.
The SCCE resource sharing assumptions
represent the most likely scenario based
on BSEE’s knowledge of the industry.
BSEE also considered a low cost
scenario and a high cost scenario for
these proposed requirements that vary
the assumptions for resource sharing
and purchase of SCCE by operators. See
Section 4.e of the Initial RIA for details
on the costs associated with these
scenarios.
ix. Relief Rig Requirements: When
conducting exploratory drilling or
working below the surface casing,
operators on the Arctic OCS would be
required to have a relief rig, different
from their primary drilling rig, staged in
a location such that it can arrive on site,
drill a relief well, kill and abandon the
original well, and abandon the relief
well prior to expected seasonal ice
encroachment at the drill site, but no
later than 45 days after the loss of well
control. In estimating the costs of this
provision, BSEE included relief rig
equipment capital costs and relief rig
documentation costs, but did not
include potential costs of the maximum
7 additional days (above the baseline)
that drilling or work below the surface
casing could not take place each season
as a result of the maximum 45-day
timeframe. ISOBSEE lacks data on how
such a limitation would affect future
exploratory drilling operations. BSEE
requests information on the potential
costs, if any, due to the cessation of
drilling or other work below the surface
casing up to 7 days (beyond the
baseline) earlier than would otherwise
occur without the proposed relief rig
requirement. Any such comments
9951
should account for the benefits of other
operations (such as maintenance and, in
some cases, drilling a second top hole)
that could continue on the site after
drilling or work below the surface
casing ceases.
x. Additional Auditing Requirements:
This provision would increase the
SEMS audit frequency and facility
coverage for Arctic OCS exploratory
drilling operations.
xi. Real-time Location Tracking
Requirements: This proposed provision
describes additional information
requirements for the emergencyresponse action plan section of the
OSRP for operators conducting
exploratory drilling on the Arctic OCS.
Operators would be required to describe
how they would maintain an effective
tracking and management system that is
able to locate in real-time all response
equipment and personnel conducting
response activities, or transiting to and
from the response site(s), and to
maintain a current picture of resources
entering and exiting staging areas and
the operational status of those resources.
xii. IOP Requirements: The proposed
rule would require operators proposing
to conduct exploratory drilling
operations on the Arctic OCS to develop
an IOP for each proposed exploratory
drilling program on the Arctic OCS, and
to submit the IOP to BOEM at least 90
days in advance of filing an EP.
xiii. Planning Information
Requirements to Accompany EPs: This
includes proposed additional
information requirements for planning
information that must accompany EPs
for operators proposing to conduct
exploration activities in the Arctic OCS
Region.
xiv. Industry Familiarization with the
New Rule: Assuming the new regulation
takes effect, industry would need to
read and interpret the rule. Through this
review, operators would familiarize
themselves with the structure of the
new rule and identify any new
provisions relevant to their operations.
Operators also would evaluate whether
they must take any new action to
achieve compliance with the rule.
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
EXHIBIT 2—10-YEAR AVERAGE ANNUAL COSTS BY PROVISION (WITH NO DISCOUNTING)
10-year average
annual costs: alternative 1 (with 7day BOP testing
requirement)
Provision
a. Additional Incident Reporting Requirements ...........................................................................................
b. Additional Pollution Prevention Requirements ........................................................................................
c. Additional Requirements for Securing Wells ...........................................................................................
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E:\FR\FM\24FEP2.SGM
$5,374
$13,585
$24,000,000
24FEP2
1-year average
annual costs: alternative 2 (without 7-day BOP
testing requirement)
$5,374
$13,585
$24,000,000
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EXHIBIT 2—10-YEAR AVERAGE ANNUAL COSTS BY PROVISION (WITH NO DISCOUNTING)—Continued
10-year average
annual costs: alternative 1 (with 7day BOP testing
requirement)
Provision
d. Additional BOP Pressure Testing Requirements ....................................................................................
e. Real-time Monitoring Requirements ........................................................................................................
f. Additional Information Requirements for APDs .......................................................................................
g. Incorporation of API RP 2N, Third Edition ..............................................................................................
h. Additional SCCE Requirements ..............................................................................................................
i. Relief Rig Requirements ...........................................................................................................................
j. Additional Auditing Requirements ............................................................................................................
k. Real-time Location Tracking Requirements ............................................................................................
l. IOP Requirements ....................................................................................................................................
m. Planning Information Requirements to Accompany EPs .......................................................................
n. Industry Familiarization with the New Rule .............................................................................................
TOTAL ..................................................................................................................................................
Exhibit 3 summarizes the costs for both
alternatives using discount rates of 3
percent and 7 percent. Alternative 1, the
proposed rule, would result in
economic costs of $1.2 billion with 3percent discounting and $1.1 billion
We also estimated the costs for
Alternative 1, the proposed rule with
the additional BOP pressure testing
requirement, and Alternative 2, the
proposed rule without the additional
BOP pressure testing requirements.
$19,2000,000
$2,208,000
$16,771
$9,240
$31,471,823
$55,208,133
$249,482
$121,044
$125,167
$28,702
$313
$132,657,635
1-year average
annual costs: alternative 2 (without 7-day BOP
testing requirement)
$0
$2,208,000
$16,771
$9,240
$31,471,823
$55,208,133
$249,482
$121,044
$125,167
$28,702
$313
$113,457,635
with 7-percent discounting over 10
years. This estimate assumes the cost
associated with staging a standby relief
rig as outlined in Section VI.B.3.(i.e.,
Relief Rig Capital Costs.
EXHIBIT 3—SUMMARY OF MONETIZED COSTS 1 2
Year
Industry costs:
alternative 1
Industry costs:
alternative 2
Government
costs
Total costs:
alternative 1
Total costs:
alternative 2
A
B
C
D=A+C
E=B+C
294,689,955
304,631,665
35,717,099
322,562,375
52,406,644
62,678,863
63,065,863
63,129,138
62,678,863
63,065,863
288,689,955
298,631,665
23,717,099
298,562,375
28,406,644
38,678,863
39,065,863
39,129,138
38,678,863
39,065,863
155,932
171,956
162,221
225,779
214,296
172,010
225,271
225,271
172,010
225,271
294,845,887
304,803,620
35,879,320
322,788,154
52,620,941
62,850,873
63,291,135
63,354,409
62,850,873
63,291,135
288.845,887
298,803,620
23,879,320
298,788,154
28,620,941
38,850,873
39,291,135
39,354,409
38,850,873
39,291,135
1,324,626,328
1,132,626,328
1,950,018
1,326,576,346
1,134,576,346
1,221,896,314
1,057,816,579
1,701,450
1,223,597,763
1,059,518,028
1,110,686,488
975,624,608
1,441,797
1,112,128,285
977,066,405
143,243,524
124,008,373
199,462
143,442,986
124,207,835
158,136,768
138,906,995
205,279
158,342,048
139,112,275
2015 .........................
2016 .........................
2017 .........................
2018 .........................
2019 .........................
2020 .........................
2021 .........................
2022 .........................
2023 .........................
2024 .........................
Undiscounted 10year total ..............
PV 10-year total with
3% discounting .....
PV 10-year total with
7% discounting .....
Annualized with 3%
discounting ...........
Annualized with 7%
discounting ...........
1 Totals
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
2 For
might not add because of rounding.
explanation of the 3-percent and 7-percent discounting methodology, see n. 2 in Exhibit 24 of the Initial RIA.
5. Benefits
Many of the potential benefits of the
proposed rule—based primarily on
preventing or reducing the duration or
severity of catastrophic oil spills—are
difficult to quantify. The proposed rule
would benefit society and the
environment by reducing the potential
for an incident resulting in an oil spill
and, if an incident does occur, by
reducing the duration or severity of the
spill. The objective of the proposed rule
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is to ensure safe and responsible oil and
gas drilling on the Arctic OCS resulting
in increased safety for personnel;
protection of the coastal, human, and
marine environments and of species;
and reducing potential conflicts
between OCS oil and gas activities and
the Alaska Natives’ ability to conduct
subsistence activities. The magnitude of
these benefits, however, is uncertain
and highly dependent on the actual
reduction in the probability of incidents
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and the effectiveness of stopping or
containing a spill already underway.
The following break-even analysis
describes the reduction in the duration
of a catastrophic oil spill that would be
needed to generate certain quantifiable
benefits equal to or greater than the
estimated costs associated with this
proposed rule. In addition, because the
probability and length of a catastrophic
oil spill would be reduced, other
benefits—beyond what we captured in
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the break-even analyses—would result
from the proposed rule. Due to
challenges in measuring these
additional benefits, we do not offer a
quantitative assessment of them;
instead, we present a qualitative
discussion.
i. Break-Even Analysis: BOEM and
BSEE conducted a break-even analysis
of the proposed rule (Alternative 1)
because of the difficulties associated
with estimating the benefits of reducing
the probability and consequences of a
catastrophic oil spill and the
uncertainty and measurement problems
associated with several categories of
benefits.16
For the proposed rule, using the
estimated discounted costs at 3 and 7
percent and the potential benefits (in
terms of avoided costs of incidents), we
calculated a break-even number of
avoided days of spilled oil if a
catastrophic oil spill were to occur. This
estimate reflects the number of avoided
days of spilled oil needed for the
proposed rule to achieve at least zero
net benefits. Any avoided days of
spilled oil greater than these break-even
points result in the proposed rule’s
achieving positive net benefits, should a
catastrophic spill occur (i.e., it is costbeneficial). We also show the estimated
total cost of a catastrophic oil spill
relative to the total cost of the proposed
rule. Exhibit 4 presents the total cost of
a catastrophic spill and the 10-year cost
of the rule.
EXHIBIT 4—TOTAL COST OF A CATASTROPHIC OIL SPILL COMPARED TO THE 10-YEAR COST OF THE RULE
Cost of a spill
($ millions)
Location
Low
Chukchi Sea ............................................................................
Beaufort Sea ............................................................................
Quantifiable costs of a catastrophic oil
spill in the Chukchi Sea range from
$10.07 billion to $15.75 billion and in
the Beaufort Sea from $12.16 billion to
$27.77 billion. Thus, quantifiable costs
of an oil spill are more than the cost of
the proposed rule; however, the
10-year cost of the rule
($ millions)
High
$10,074.2
12,155.9
7% Discounting
$15,752.6
27,771.5
probability of a catastrophic oil spill is
very low. A catastrophic spill resulting
from exploratory drilling on the Arctic
OCS, for example, is considered
unlikely due to the nature of the
geology, shallow water depth, and
simplicity of the wells. However, due to
3% Discounting
$1,112
1,112
$1,224
1,224
the limited drilling history on the Arctic
OCS, projections cannot be made with
certainty. Exhibit 5 presents a summary
of the results of the break-even analysis
for the proposed rule; a full description
of the results and methodology is
contained in the Initial RIA.
EXHIBIT 5—BREAK-EVEN RESULTS: NUMBER OF DAYS OF OIL SPILL PREVENTED
Cost of spill per
day
($ millions)
Location
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Chukchi Sea ..........................................
Beaufort Sea ..........................................
10-year cost of the rule
($ millions)
7% Discounting
$177.5
113.6
Break-even
number of days
3% Discounting
$1,112
1,112
7% Discounting
$1,224
1.224
6.3
9.8
3% Discounting
6.9
10.8
Over the 10-year cost analysis period,
the number of avoided/reduced days of
a catastrophic oil spill needed to breakeven is between 6.3 and 6.9 days for the
Chukchi Sea and 9.8 and 10.8 days for
the Beaufort Sea. To provide context,
the BOEM Case Study estimates that the
duration of a catastrophic incident in
the Chukchi Sea could be between 40
and 75 days and an incident in the
Beaufort Sea could be between 60 and
300 days. One of the key goals of the
proposed SCCE and relief rig provisions
is to reduce the duration of such a spill
should one occur.
BOEM and BSEE believe that this
break-even analysis is an appropriate
way to evaluate the costs and benefits of
the proposed rule under the
circumstances. However, we invite
comments on the assumptions, data,
and methods used in this break-even
analysis, as described fully in the Initial
RIA. We also invite comments on
whether there is a better alternative
method for evaluating the costs and
benefits of the proposed rule.
ii. Qualitative Benefits: Because
BOEM and BSEE used a conservative
approach in the valuation of an oil spill
in the break-even analysis, the
identified cost of a catastrophic oil spill
can be considered a lower bound of the
true cost of such an event to society and
of the potential benefits from preventing
such an event. Although the break-even
analysis captures some of the
environmental damage associated with a
catastrophic oil spill, the analysis is
limited because it only considers the
environmental amenities that
researchers could identify and
monetize. Natural resource valuation is
complex; many factors contribute to
how society values a resource, including
both use and non-use values of the
resources. Many use values can be
estimated by behavior and market
transactions (for example, using the
harvest value of yields in the Arctic
OCS region). Many other use values,
however, might not be related to a
market and are, therefore, difficult to
monetize. For example, Alaska Native
communities place a high value on the
cultural amenities related directly to the
use of the region. Because communities
do not trade cultural amenities in
markets, we are unable to estimate a
direct value of these resources.
Non-use values are much harder to
estimate; common non-use values
include existence values and bequest
16 A catastrophic oil spill is a low-probability,
high-consequence event because it is an event that
occurs infrequently, but has large consequences
when it does occur. For such events, it is difficult
to know with any certainty the probability of the
event actually occurring, or to precisely determine
the reduction in the probability of occurrence that
a proposed regulation would actually achieve. In
addition, the consequences of an oil spill depend
on several factors, including the type and amount
of oil, the location of the spill, the areal distribution
of the release, the sensitivity of the ecosystem
affected, and the weather.
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mstockstill on DSK4VPTVN1PROD with PROPOSALS2
values. Individuals place a value on
environmental amenities by knowing
that preservation and protection of the
region exists even if those individuals
do not intend to visit the region.
Bequest values relate to individuals
placing a value on the preservation of
regions for future generations even if
they do not intend to use the resource
themselves. For example, many nonnative Alaskans, and many other
Americans who do not live in Alaska,
place a very high value on protecting
the health of the ecosystem, including
the sensitive environment and wildlife,
of this largely frontier area. Thus, the
impact of a catastrophic oil spill, would
have extremely high cultural and
societal costs, and prevention of such a
catastrophe would have
correspondingly high cultural and
societal benefits. Capturing these
complex values is difficult because they
are not traded in markets. Because we
are unable to monetize all aspects of the
consequences of an oil spill, the
estimate we used in the break-even
analysis captures only a portion of the
value to society.
The objective of the proposed
rulemaking is to ensure safe and
responsible oil and gas drilling on the
Arctic OCS, which would result in
increased safety for personnel,
protection of the marine environment
and species, protection of Alaska
Natives’ cultural values, and removal of
impediments to Alaska Natives’
subsistence use. In addition, the
proposed rule achieves better
coordination among BSEE, BOEM, and
other government agencies. For
example, the information required in
proposed § 550.204 would facilitate
interagency coordination between DOI
and other relevant Federal agencies, as
recommended in the 60-Day Report.
Exhibit 6 presents the provisions of
the proposed rule along with their
primary qualitative benefits, such as
improving oversight of operations by
Federal agencies, minimizing natural
resource and ecosystem impacts,
reducing the risk of a spill, improving
containment of a spill, and a general
benefit.
EXHIBIT 6—EXAMPLES OF QUALITATIVE
BENEFITS BY PROVISION
Provision
Primary benefits
a. Additional Incident
Reporting Requirements.
b. Pollution Prevention Requirements.
Improves oversight of
operations by Federal agencies.
Minimizes natural resource impacts.
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EXHIBIT 6—EXAMPLES OF QUALITATIVE C.E.O. 13563
BENEFITS BY PROVISION—Continued
E.O. 13563 reaffirms the principles of
Provision
c. Additional Requirements for Securing
Wells.
d. Additional BOP
Pressure Testing
Requirements.
e. Real-time Monitoring Requirements.
f. Additional Information Requirements
for APDs.
g. Incorporation of
API RP 2N, Third
Edition.
h. Additional SCCE
Requirements.
i. Relief Rig Requirements.
j. Additional Auditing
Requirements.
k. Real-time Location
Tracking Requirements.
l. IOP Requirements
m. Planning Information Requirements
to Accompany EPs.
n. Industry Familiarization with the
New Rule.
Primary benefits
Reduces risk of a
spill.
Reduces risk of a
spill.
Reduces risk of a
spill.
Improves oversight of
operations by Federal agencies.
Reduces risk of a
spill.
Improves containment
of a spill.
Improves containment
of a spill.
Improves oversight of
operations by Federal agencies.
Improves oversight of
operations by Federal agencies.
Reduces risk of a
spill.
Improves oversight of
operations by Federal agencies.
General.
6. Conclusion
The proposed rule would reduce both
the overall risk of oil spills on the Arctic
OCS and the consequences of a spill if
one were to occur. We conducted a
break-even analysis of the benefits of the
proposed rule. In addition, we included
a qualitative discussion of potential
benefits of the proposed rule that could
not be quantified or monetized. The
break-even analysis showed that for the
Chukchi Sea, a minimum reduction of
6.3 to 6.9 days for a catastrophic oil spill
would result in a cost-beneficial rule
over the 10-year study period. For the
Beaufort Sea, we estimated that a
minimum reduction of between 9.8 and
10.8 days for a catastrophic oil spill
would result in a cost-beneficial rule
over the 10-year study period.
In addition to the quantifiable
benefits, there are significant qualitative
benefits, including protection of Alaska
Native communities’ cultural resources
and subsistence needs and other
unquantifiable environmental, cultural,
and societal benefits. Accordingly,
BOEM and BSEE have determined that
the benefits of the proposed rule justify
its potential costs and that it is
appropriate to proceed with this
proposed rule.
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E.O. 12866 while calling for
improvements in the Nation’s regulatory
system to promote predictability, to
reduce uncertainty, and to use the best,
most innovative, and least burdensome
tools for achieving regulatory ends. In
addition, E.O. 13563 directs agencies to
consider regulatory approaches that
reduce burdens and maintain flexibility
and freedom of choice for the public
where these approaches are relevant,
feasible, and consistent with regulatory
objectives. It also emphasizes that
regulations must be based on the best
available science and that the
rulemaking process must allow for
public participation and an open
exchange of ideas. We developed this
proposed rule in a manner consistent
with these requirements. BOEM and
BSEE worked closely with engineers
and technical staff to ensure this
rulemaking follows sound engineering
principles and options through research,
standards development, and interaction
with industry.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA),
5 U.S.C. 601–612, requires agencies to
analyze the economic impact of
proposed regulations when a significant
economic impact on a substantial
number of small entities is likely and to
consider regulatory alternatives that will
achieve the agency’s goals while
minimizing the burden on small
entities. In addition, the Small Business
Regulatory Enforcement Fairness Act of
1996, 5 U.S.C. 601note, requires
agencies to produce compliance
guidance for small entities if the rule
has a significant economic impact. For
the reasons explained in this section,
BOEM and BSEE have concluded that
the proposed rule is likely to have a
significant economic impact on a
substantial number of small entities
and, therefore, a regulatory flexibility
analysis is required. This Initial
Regulatory Flexibility Analysis assesses
the impact of the proposed rule on small
entities, as defined by the applicable
Small Business Administration size
standards.
1. Description of the Reasons Why
Action by the Agency Is Being
Considered
Although a comprehensive OCS oil
and gas regulatory program exists, DOI
engagement with partners and
stakeholders reveals the need for new
and revised regulatory measures for
exploratory drilling by floating drilling
vessels and ‘‘jackup rigs’’ (collectively
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known as MODUs) on the Arctic OCS.
The U.S. Arctic region, as recognized by
the U.S. and defined in the U.S. Arctic
Research and Policy Act of 1984,
encompasses an extensive marine and
terrestrial area; but this proposed rule
focuses solely on the OCS within the
Beaufort Sea and Chukchi Sea Planning
Areas.
BOEM and BSEE have undertaken
extensive environmental and safety
reviews of potential oil and gas
operations on the Arctic OCS. These
reviews, along with concerns expressed
by environmental organizations and
Alaska Natives, reinforce the need to
develop additional measures
specifically tailored to the operational
and environmental conditions of the
Arctic OCS. After considering the input
provided by various partners and
stakeholders and DOI’s direct
experience from Shell’s 2012 Arctic
operations, BOEM and BSEE have
concluded that additional exploratory
drilling regulations would enhance and
clarify existing regulations and would
be appropriate for a more holistic Arctic
OCS oil and gas regulatory framework.
This proposed rulemaking is intended
to ensure that Arctic OCS exploratory
drilling operations are conducted in a
safe and responsible manner that
considers the unique conditions of
Arctic OCS drilling and Alaska Natives’
cultural traditions and need to access
subsistence resources. The Arctic region
is known for its oil and gas resource
potential, its vibrant ecosystems, and
the Alaska Native communities.
Extreme environmental conditions,
geographic remoteness, and a relative
lack of fixed infrastructure and existing
operations characterize the region.
These factors are key in considering the
feasibility, practicality, and safety of
conducting offshore oil and gas
activities on the Arctic OCS.
This proposed rule would add to and
revise existing regulations in 30 CFR
parts 250, 254, and 550 for Arctic OCS
oil and gas activities. The proposed rule
would focus on Arctic OCS exploratory
drilling activities that use MODUs and
related operations during the Arctic
OCS open-water drilling season. This
proposed rule would address several
important issues and objectives,
including ensuring that operators:
i. Design and conduct exploration
programs in a manner suitable for Arctic
OCS conditions;
ii. Develop an IOP that would address
all phases of the proposed Arctic OCS
exploration program and submit the IOP
to BOEM at least 90 days in advance of
filing the EP;
iii. Have access to and the ability to
promptly deploy SCCE, while drilling
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below or working below the surface
casing;
iv. Have access to a separate relief rig
located so that it could timely drill a
relief well, in the event of a loss of well
control, under the conditions expected
at the site;
v. Have the capability to predict,
track, report, and respond to ice
conditions and adverse weather events;
vi. Effectively manage and oversee
contractors; and
vii. Develop and implement OSRPs
designed and executed in a manner
suitable for the unique Arctic OCS
operating environment and have the
necessary equipment, training, and
personnel for oil spill response on the
Arctic OCS.
The proposed rule would further the
Nation’s interest in exploring frontier
areas, such as those in the Arctic region,
and would establish specific operating
models and requirements for the
extreme, changing conditions that exist
on the Arctic OCS. The proposed
regulations would require
comprehensive planning of operations,
especially for emergency response and
safety systems. The proposed rule
would seek to institutionalize a
proactive approach to offshore safety. A
goal of the proposed rule is to identify
possible vulnerabilities early in the
planning process so that corrections can
be made to decrease the potential for an
incident occurring. The requirements in
the proposed rule also are designed to
ensure that those plans would be
executed in a safe and environmentally
protective manner, despite the
challenges the Arctic presents.
2. We identified the following
provisions of the proposed rule as
having a cost to industry:
i. Additional incident reporting
requirements;
ii. Pollution prevention requirements;
iii. Additional requirements for
securing wells;
iv. Additional BOP pressure testing
requirements;
v. Real-time monitoring requirements;
vi. Additional information
requirements for APDs;
vii. Incorporation of proposed draft
API RP 2N;
viii. Additional SCCE requirements;
ix. Relief rig requirements;
x. Additional auditing requirements;
xi. Real-time location tracking
requirements;
xii. IOP requirements;
xiii. Additional requirements for EPs;
and
xiv. Industry familiarization with the
rule.
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3. Succinct Statement of the Objectives
of, and Legal Basis for, the Proposed
Rule
The objectives and legal basis are
described in part II, Background, of the
proposed rule.
4. Description of and, Where Feasible,
an Estimate of the Number of Small
Entities to Which the Proposed Rule
Will Apply
The RFA defines small entities as
small businesses, small nonprofits, and
small governmental jurisdictions. We
have identified no small nonprofits or
small government jurisdictions that the
proposed rule would impact, so this
analysis focuses on impacts on small
businesses (hereafter referred to as
‘‘small entities’’). A small entity is one
that is ‘‘independently owned and
operated and which is not dominant in
its field of operation.’’ 17 The definition
of small business varies from industry to
industry to capture industry size
differences properly.
The proposed rule would affect
operators and holders of Federal oil and
gas leases that could conduct
exploratory drilling on the Arctic OCS.
According to BOEM’s list of
leaseholders on the Arctic OCS as of
May 2014, 10 businesses hold leases on
the Arctic OCS.18 Three of these
businesses are anticipated to conduct
exploratory drilling on the Arctic OCS
over the next 10 years, although any
business holding a lease could conduct
exploratory drilling on the Arctic OCS
and would thus be subject to the
requirements of this proposed rule.
Businesses subject to this rule fall
under North American Industry
Classification System codes 211111
(Crude Petroleum and Natural Gas
Extraction) and 213111 (Drilling Oil and
Gas Wells). For these classifications, a
small business is defined as one with
fewer than 500 employees. Based on
this criterion, only one business
currently holding a Federal oil and gas
lease on the Arctic OCS is considered
small. Although BOEM and BSEE do not
expect a small entity to conduct
exploratory drilling on the Arctic OCS
during the 10-year analysis period, any
business holding a lease could operate
on the Arctic OCS. Using the number of
businesses holding such leases as the
universe subject to this rule, 10 percent
(1 of 10) of the firms are considered
small. Thus, the proposed rule would
affect a ‘‘substantial number’’ of small
17 See
5 U.S.C. 601.
www.boem.gov/uploadedFiles/BOEM/
About_BOEM/BOEM_Regions/Alaska_Region/
Leasing_and_Plans/Leasing/Alaska_Lease_
Holdings_by_Owner_or_Partial_Owner.pdf.
18 See
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i. Total Cost Estimates by Provision
BOEM and BSEE assessed the costs
associated with the proposed regulation
by estimating the cost for a hypothetical
small operator. We assumed that this
operator would conduct an exploratory
drilling program with one rig, two wells,
two APDs, and one OSRP, IOP, and EP
each. For each provision, we estimated
the per-rig, per-well/APD, per-OSRP,
per-IOP, and per-EP cost, where
applicable. Following is a summary of
the unit costs using the estimates
developed in the RIA.20 Please refer to
the Initial RIA for details on the cost
estimates.
For the incident reporting activities,
we estimated the per-rig cost at $1,146,
including both the costs for ice
movement activity oral reports ($313
per rig) and the costs associated with
written reports ($834 per rig). For the
pollution prevention requirements, we
estimated the costs per rig to capture
and transport mud and cuttings to be
$4,245. For the additional requirements
for securing wells, we included both the
capital costs ($2,000,000) and the labor
and operational costs ($3,000,000) for a
total per-well cost of $5,000,000.
We assessed the costs for Alternative
1 (the proposed rule with the additional
BOP pressure-testing requirements) and
Alternative 2 (the proposed rule without
the additional BOP pressure-testing
requirements). For the additional BOP
pressure-testing requirements included
under Alternative 1, BSEE included the
per-rig labor cost of $6,000,000. These
costs are not included in the cost
estimates for Alternative 2. (See Section
6 following for details on the
alternatives.) For the proposed real-time
monitoring requirements, we estimated
a per-rig labor cost of $690,000. For the
proposed additional information
requirements for the APDs, we
estimated a per-rig labor cost of $1,491
and a per-well labor cost of $1,305. For
the proposed incorporation of draft API
RP2N, Third Edition, we estimated a
per-rig labor cost of $1,918. For the
enhanced auditing requirements, we
estimated a per-rig labor cost of
$129,000. For the proposed real-time
tracking requirements, we estimated a
per-OSRP labor cost of $401.
In addition, we included a cost of
$102,624 ($63,274 upfront cost plus
$39,350 annual cost) per rig to account
for the purchase, operation, and
maintenance of an Automatic
Identification System (AIS) as an
example of costs to comply with the
real-time tracking requirements for oil
spill response resources.21 For the
proposed IOP requirements, we
estimated a per-IOP labor cost of $8,633.
For the proposed planning information
requirements to accompany the EPs, we
estimated a per-EP labor cost of $4,316.
Finally, we estimated a per-operator
cost of $1,042 for the time needed for an
operator to become familiar with the
rule.
The proposed SCCE requirements
have several different cost components
for both rigs and wells. We estimated a
one-time capital cost per rig of
$270,000,000 and an annual
redeployment cost of $1,200,000 per rig.
For the aggregate cost of the SCCE, we
varied the assumptions for purchase and
redeployment costs based on whether
the operator purchases the equipment or
engages in resource sharing, as
discussed later. For the Regional
Supervisor-initiated tests, we estimated
a per-rig cost of $500,000. For the stump
tests, we assumed that the operator
would use a pre-positioned capping
stack (PPCS) and estimated that each
PPCS stump test costs $160,208 per
well. We assumed one stump test before
installation on each well and one stump
test before deployment. Although the
operator could instead use a dry-stored
capping stack, we conservatively
assumed that the operator would use a
PPCS, which results in higher costs. For
the proposed information requirements
for the well design change, we estimated
a per-well labor cost of $959. We also
estimated a per-well labor cost of $1,174
to maintain the SCCE records and a perwell labor cost of $5,755 for the APD
documents. The total SCCE
requirements sum to $271,700,000 per
rig and $328,305 per well.22
For the proposed relief rig
requirements, we included the costs
associated with the proposed
information documentation
requirements for the relief rig. We
estimated the labor cost associated with
the documentation requirements for the
relief rig to be $14,591 per rig. As
discussed in the Initial RIA, we do not
include costs associated with the
proposed 45-day maximum limit on the
time necessary to complete the required
relief rig activities under Section
250.472 because we lack information
regarding potential costs, if any, above
the baseline that might accrue from the
cessation of drilling or other work below
the surface casing under this proposed
requirement.
We present the least-cost means to
comply with the proposed rule, and
thus assume that a small entity would
not incur the costs of a standby relief rig
and would enter into a resource sharing
agreement to comply with the relief rig
requirements. If, however, a small entity
chooses to deploy a dedicated standby
relief rig to comply with regulatory
requirements, it could incur costs of
approximately $276 million per rig, per
season.
Exhibit 7 presents the unit costs per
provision for a small operator. These
estimates include the full cost of the
proposed SCCE requirements, assuming
no resource sharing with another
operator, and costs associated with the
enhanced BOP pressure testing
requirements under Alternative 1.
19 See the Initial RIA for the proposed rule for
details on baseline assumptions. We state all costs
in 2012 constant dollars.
20 Totals might not add because of rounding.
21 As explained in the initial RIA, proposed
§ 254.80(c) does not require any specific real-time
tracking system, so we used AIS as a representative
system for costs analysis purposes.
22 These totals are derived, respectively, as
follows: ($270,000,000 + $1,200,000 + $500,000)
and ($160,208 + $160,208 + $959 + $1,174 +
$5,755).
entities, defined by BOEM and BSEE as
10 percent or more of the potentially
affected entities. Thus, although we do
not expect that a small entity would
conduct exploratory drilling during the
analysis period, to be conservative, we
have conducted this RFA analysis to
demonstrate the likely effects the
proposed rule would have on a
hypothetical small operator.
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5. Description of the Projected
Reporting, Recordkeeping and Other
Compliance Requirements of the
Proposed Rule, Including an Estimate of
the Classes of Small Entities That Will
Be Subject to the Requirement and the
Type of Professional Skills Necessary
for Preparation of the Report or Record
BOEM and BSEE have estimated the
incremental costs for small oil and gas
leaseholders that decide to engage in
exploratory drilling on the Arctic OCS.
This analysis reflects only costs
associated with activities and capital
investments required by the proposed
rule that represent a change from the
baseline. The baseline for this proposed
rule includes existing regulations,
standard industry practices, operator
prudence, and assumptions based on
requirements for Shell’s 2012 Arctic
OCS operations that were imposed by
BOEM or BSEE under their existing
regulatory authorities.19 Cost estimates
included in this analysis for the
provisions of the proposed rule are
those presented in detail in the Initial
RIA.
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EXHIBIT 7—UNIT COST OF THE PROPOSED RULE BY PROVISION (WITH NO RESOURCE SHARING)
Provision
Cost per rig
Cost per well/APD
Cost per operator
(EP/IOP/OSRP)
a. Additional Incident Reporting Requirements .......................................
b. Pollution Prevention Requirements .....................................................
c. Additional Requirements for Securing Wells .......................................
d. Additional BOP Pressure Testing Requirements ................................
e. Real-time Monitoring Requirements ....................................................
f. Additional Information Requirements for APDs ...................................
g. Incorporation of draft API RP 2N, Third Ed. .......................................
h. Additional SCCE Requirements ..........................................................
i. Relief Rig Requirements .......................................................................
j. Additional Auditing Requirements ........................................................
k. Real-time Location Tracking Requirements ........................................
l. IOP Requirements ................................................................................
m. Planning Information Requirements to Accompany Eps ...................
n. Industry Familiarization with the New Rule .........................................
$1,146
4,245
....................................
6,000,000
690,000
1,491
1,918
271,700,000
14,591
129,000
102,624
....................................
....................................
....................................
....................................
....................................
5,000,000
....................................
....................................
1,305
....................................
328,305
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
....................................
401
8,633
4,316
1,042
Total Annual Cost Per Rig/Well/Operator 1 ......................................
278,645,016
5,329,610
14,393
1 Totals
might not add because of rounding.
ii. Total Cost Burden for Small Entities
We calculated the cost to a single
small operator under different
alternatives and differing assumptions
regarding resource sharing of the SCCE.
We assumed that the SCCE purchase
cost would be $270,000,000 and the
annual redeployment cost would be
$1,200,000.
We estimated the highest-cost
scenario for a small operator to present
the most conservative estimate possible
of the potential for a significant
economic impact. Under this highestcost scenario, the small operator would
need to purchase and deploy the SCCE
(i.e., no resource sharing) and would be
subject to the additional BOP pressuretesting requirements under Alternative
1. We also estimated the costs of
Alternative 2 (i.e., no additional BOP
pressure-testing requirements) assuming
no resource sharing of SCCE. Under the
lowest-cost scenario, the small operator
would employ resource sharing of SCCE
and would not be subject to the
additional BOP pressure-testing
requirements (as in Alternative 2). We
also estimated the costs of Alternative 1
assuming resource sharing of SCCE.
Next, we estimated the average annual
revenue of an affected small operator.
We used an annual revenue estimate of
$45.7 million for the small operator as
calculated in the final RIA for BSEE’s
‘‘Oil and Gas and Sulphur Operations
on the Outer Continental Shelf: Oil and
Gas Production Safety Systems’’
rulemaking (77 FR 50856, Aug. 22,
2012).23 We used this estimate of
average annual revenue to calculate the
ratio of total costs of the proposed rule
as a percentage of average annual
revenue to determine if the proposed
rule would result in a significant
economic impact on small entities.
Exhibit 8 presents estimates of the
total first-year costs to a small operator
under each scenario and the total firstyear costs as a percentage of average
annual revenue. Under all scenarios, the
first-year costs as a percentage of
revenue surpass the 1-percent threshold
used to define a significant economic
impact. Even under the lowest-cost
scenario, assuming that the operator
would engage in resource sharing of the
SCCE and would not be subject to the
additional BOP pressure-testing
requirements (as in Alternative 2), the
small operator would experience a total
first-year cost equal to 29 percent of
their average annual revenue. For the
scenarios that assume no resource
sharing of SCCE, the total first-year costs
as a percentage of revenue are greater
than 100 percent, indicating that the
total first-year costs the small operator
would experience would be greater than
its total average annual revenue.24
EXHIBIT 8—FIRST-YEAR COSTS AS A PERCENTAGE OF AVERAGE ANNUAL REVENUE PER OPERATOR
Total first-year cost
Total first-year cost as
percent of revenue
A
B = A/$45.7 million
Scenario
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Alternative
Alternative
Alternative
Alternative
1
2
1
2
with
with
with
with
No Resource Sharing of SCCE ..........................................................................
No Resource Sharing of SCCE ..........................................................................
Resource Sharing of SCCE ................................................................................
Resource Sharing of SCCE ................................................................................
$289,318,628
283,318,628
19,318,628
13,318,628
633
620
42
29
Exhibit 9 presents estimates of the
total annual ongoing costs (the costs in
the second year and after) to a small
operator under each scenario, or the
costs incurred on an annual basis after,
and not including, the first-year of the
23 See 77 FR 50856 (August 22, 2012). The final
RIA for that rulemaking can be viewed at
www.regulations.gov/#!documentDetail;D=BSEE–
2012–0002–0047. The data in the source document
are from the Office of Natural Resources Revenue.
The data source reports the total 2009 small
business revenue to be $4,113,000,000. We
calculated the average revenue per small business
by dividing the total small business revenue by the
number of small businesses ($4,113,000,000/90) to
obtain an average of $45,700,000 per operator.
24 As stated earlier, BOEM and BSEE do not
expect an actual small operator to conduct
exploratory drilling on the Arctic OCS during the
10-year period of this analysis, although we have
prepared this analysis to be conservative (since one
current Arctic OCS lessee is a small entity). Thus,
this analysis considers the average annual revenue
of small OCS operators.
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analysis period. Exhibit 9 also presents
the total annual ongoing costs as a
percentage of average annual revenue.
Under all scenarios, the annual ongoing
costs as a percentage of revenue surpass
the 1-percent threshold used to define a
significant economic impact. Under
Alternative 1, a small operator would
experience total annual ongoing costs
equal to 42 percent of their average
annual revenue, and under Alternative
2, total annual ongoing costs to small
operators would be equal to 29 percent
of average annual revenue. Costs after
the first year do not vary based on SCCE
resource-sharing assumptions because
we assumed that SCCE capital costs (if
any) would be incurred in the first year.
BOEM and BSEE conclude that the
proposed rule would have a ‘‘significant
economic impact’’ on small operators
because costs are greater than 1 percent
of revenue in every year of the analysis
period. Although costs are anticipated
to be lower for operators after the first
year, during which the operator is
assumed to purchase capital equipment,
annual costs are still estimated to be
well above the 1-percent threshold in
the subsequent years of the 10-year
analysis period.
EXHIBIT 9—ANNUAL ONGOING COSTS AS A PERCENTAGE OF AVERAGE ANNUAL REVENUE PER SMALL OPERATOR
Total annual ongoing
cost
Total annual ongoing
cost as percent of
revenue
A
B = A/$45.7 million
Scenario
Alternative
Alternative
Alternative
Alternative
1
2
1
2
with
with
with
with
No Resource Sharing of SCCE ..........................................................................
No Resource Sharing of SCCE ..........................................................................
Resource Sharing of SCCE ................................................................................
Resource Sharing of SCCE ................................................................................
The conclusion that the rule would
have a ‘‘significant economic impact’’
on small operators is based on past
revenue of operators and does not
account for any potential increase in
revenue that operators might experience
if Arctic OCS exploratory drilling
operations lead to production. Operators
conducting exploratory drilling on the
Arctic OCS that experience a significant,
economically viable discovery of oil or
natural gas and that proceed to the
production phase could experience a
significant increase in revenue. Thus,
the analysis presented in this section
could understate the revenue, resulting
in an overstatement of the impact of the
rule when expressed as the ratio of costs
to annual revenue.25
6. Identification of All Relevant Federal
Rules That May Duplicate, Overlap, or
Conflict With the Proposed Rule
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The proposed rule does not conflict
with any relevant Federal rules or
duplicate or overlap with any Federal
rules in any way that would
unnecessarily add cumulative
regulatory burdens on small entities
without any gain in regulatory
benefits.26 However, BOEM and BSEE
request comments identifying any
25 Conversely, oil and gas exploration has
inherent financial risk in that the exploration
activities might not yield an economically viable
discovery of oil or natural gas.
26 The proposed revision to 30 CFR 250.300(b)
that would prohibit the discharge of petroleumbased mud and associated cuttings may overlap
with existing EPA general permits for the Beaufort
and Chukchi Seas under the National Pollution
Discharge Elimination System regulations (40 CFR
part 122) while those permits remain in effect.
However, the proposed rule would not add any
regulatory burden to any small entity in that regard.
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Federal rules that may duplicate,
overlap, or conflict with the proposed
rule.
7. Description of Significant
Alternatives to the Proposed Rule
Several provisions of the proposed
rule are performance based, which will
enable operators to devise optimal
strategies for reducing the cost burden
of the proposed rule. In addition,
operators might be able to reduce costs
through resource sharing. BOEM and
BSEE strongly encourage operators
proposing exploratory drilling activities
on the Arctic OCS to enter into mutual
aid agreements for the sharing of
vessels, relief well rigs, and other assets
or services associated with responding
to an oil spill or other emergency.
BOEM and BSEE have considered
three major regulatory alternatives for
dealing with the safety and
environmental concerns raised by
exploration activities on the Arctic OCS:
i. Promulgate the rule changes
proposed in this proposed rule for the
Arctic OCS; or
ii. Promulgate the rule changes
described in the proposed rule without
including the 7-day BOP pressuretesting requirement for Arctic OCS
exploratory drilling operations (in
§ 250.447 of the proposed rule); or
iii. Take no regulatory action and
continue to rely on existing OCS oil and
gas regulations, industry standards, and
operator prudency.
BSEE has decided not to issue a
proposed rule without the 7-day BOP
testing requirement. Although
maintaining the testing frequency at 14
days would reduce the total costs of the
proposed rule, the additional testing
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$19,125,311
13,125,311
19,125,311
13,125,311
42
29
42
29
requirement is intended to help ensure
that BOPs deployed in the Arctic OCS
function properly and reduce the risk of
blowouts.
BOEM and BSEE also have decided to
move forward with this proposed rule,
in lieu of taking no regulatory action,
because relying on the regulatory status
quo would not address the safety and
environmental concerns partners and
stakeholders have raised and thus
would not achieve the objectives of this
proposed rule. In addition, the proposed
rule would confer additional protections
on the environment and Alaska Native
cultural activities. Further, the projected
potential for impacts on small entities is
mitigated by the fact that the agencies
do not anticipate any small entity
independently pursuing exploration
drilling on the Arctic OCS during the
10-year analysis period.
E. Unfunded Mandates Reform Act of
1995 (UMRA)
This proposed rule would not impose
an unfunded Federal mandate on State,
local, or tribal governments but would,
if finalized, create a Federal private
sector mandate that could require
expenditures exceeding $100 million in
a single year by offshore oil and gas
exploration companies operating on the
Arctic OCS. Accordingly, DOI has
prepared written statements satisfying
the applicable requirements of the
UMRA, 2 U.S.C. 1501 et seq. Those
requirements are addressed in the Initial
RIA and initial RFA analyses for this
proposed rule and in the proposed rule
itself.
Among other things, the proposed
rule, Initial RIA, and/or Initial RFA:
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1. Identify the provisions of Federal
law (OCSLA, CWA, and OPA) under
which this rule is being proposed;
2. Include a quantitative assessment
of the anticipated costs to the private
sector (i.e., expenditures on labor and
equipment) of the proposed rule; and
3. Include qualitative and quantitative
assessments of the anticipated benefits
of the proposed rule.
Since all of the anticipated
expenditures by the private sector
analyzed in the Initial RIA and the
Initial RFA analyses would be borne by
the offshore oil and gas exploration
industry in the Arctic region, the Initial
RIA and Initial RFA analyses satisfy the
UMRA requirement to estimate any
disproportionate budgetary effects of the
proposed rule on a particular segment of
the private sector (i.e., the offshore oil
and gas industry).
As discussed in the Regulatory
Planning and Review section of this
proposed rule, and explained fully in
the Initial RIA, BOEM and BSEE
considered three major regulatory
alternatives for dealing with the safety
and environmental concerns raised by
exploration activities on the Arctic OCS.
BOEM and BSEE have decided to move
forward with this proposed rule, in lieu
of the other alternatives, because those
alternatives would not as efficiently or
effectively address the safety,
environmental or sociocultural concerns
raised by various stakeholders on the
Arctic OCS or achieve the objectives of
this proposed rule.
BOEM and BSEE have determined
that the proposed rule would not
impose any unfunded mandates or any
other requirements on State, local or
tribal governments; thus, the proposed
rule would not have disproportionate
budgetary effects on such governments.
Assuming, however, that the proposed
rule might result in budgetary effects on
the Arctic region, BOEM and BSEE have
determined that it is not practical to
accurately estimate such effects. Since
the proposed rule would not impose any
requirements on any entities, other than
companies and their contractors
engaged in Arctic OCS exploration
activities, any budgetary effects in that
area would be at least indirect,
secondary results of actions or decisions
taken by regulated (or unregulated)
entities, based on a variety of
circumstances (such as the price of oil,
each entity’s overall financial health,
and the prospects of success of any
exploratory drilling). Because each of
those factors is variable and
unpredictable, it is not practical to
estimate how those factors might affect
an entity’s future decisions, or what
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indirect impacts, if any, such decisions
could have on future regional budgets.
Similarly, BOEM and BSEE have
determined that it is not reasonably
feasible to accurately estimate the
potential effects, if any, of the proposed
rule on the National economy (e.g.,
productivity, economic growth,
employment, international
competitiveness). The proposed rule, if
finalized, would only affect exploratory
drilling activities on the Arctic OCS,
and any potential impact on the
National economy would depend on
individual business decisions made by
regulated entities (e.g., whether or not to
hire new employees). Moreover, any
such decisions would likely be either
local or regional in effect and unlikely
to have any significant National
economic impacts.
F. Takings Implication Assessment
Under the criteria in E.O. 12630, this
proposed rule would not have
significant takings implications. The
proposed rule is not a governmental
action capable of interference with
constitutionally protected property
rights. A Takings Implication
Assessment is not required.
G. Federalism (E.O. 13132)
Under the criteria in E.O. 13132, this
proposed rule would not have
federalism implications. This proposed
rule would not substantially and
directly affect the relationship between
the Federal and State governments. To
the extent that State and local
governments have a role in OCS
activities, this proposed rule would not
affect that role. A Federalism
Assessment is not required.
H. Civil Justice Reform (E.O. 12988)
This proposed rule complies with the
requirements of E.O. 12988.
Specifically, this rule:
1. Meets the criteria of § 3(a) requiring
that all regulations be reviewed to
eliminate errors and ambiguity and be
written to minimize litigation; and
2. Meets the criteria of § 3(b)(2)
requiring that all regulations be written
in clear language and contain clear legal
standards.
I. Consultation With Indian Tribes (E.O.
13175)
Under the criteria in E.O. 13175,
Consultation and Coordination with
Indian Tribal Governments (dated
November 6, 2000), DOI’s Policy on
Consultation with Indian Tribes
(Secretarial Order 3317, Amendment 2,
dated December 31, 2013), and the
Alaska Native Corporation Consultation
Policy (dated August 12, 2012), we
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9959
evaluated and determined that the
subject matter of this rulemaking would
have tribal implications for Alaska
Natives. As described earlier, future
Arctic OCS exploratory drilling
activities conducted pursuant to this
proposed rule could affect Alaska
Natives, particularly their ability to
engage in subsistence and cultural
activities.
BOEM and BSEE are committed to
regular and meaningful consultation
and collaboration with tribes on policy
decisions that have tribal implications
including, as an initial step, through
complete and consistent
implementation of E.O. 13175, together
with related orders, directives, and
guidance. Therefore, BOEM and BSEE,
in coordination with the Office of the
Secretary of the Interior’s Senior Alaska
Representative, engaged in listening
sessions, Government-to-Government
Tribal consultations, and Governmentto-ANCSA Corporations consultations to
discuss the subject matter of the
proposed rule and solicit input in the
development of the proposed rule.
Government-to-Government
consultation was held in Barrow
between BOEM, BSEE, and the ICAS on
June 6, 2013, to both provide
background to and obtain information
from ICAS leaders and council
members. The following day, June 7,
2013, BOEM and BSEE met with leaders
and council members of the Native
Village of Barrow in a separate
Government-to-Government
consultation. All Alaska Native input
provided during the meetings was
subsequently provided to DOI in writing
and has been included in the
administrative record for this proposed
rule.
BOEM and BSEE also held public
listening sessions in South-central
Alaska (Anchorage) and on the North
Slope (Barrow) on June 6 and 7, 2013.
The BOEM Alaska Region notified
Alaska Native Tribes and ANCSA
Corporations of the June 6 and 7, 2013,
public listening sessions and
Government-to-Government
consultations through phone calls,
emails, newspaper announcements, and
BOEM’s Web site.
A series of follow-on meetings and
listening sessions were held June 17–20,
2013, in Anchorage resulting, in part, in
Government-to-Government
consultation between BOEM, BSEE, and
the Native Village of Nuiqsut and
Government-to-ANCSA Corporation
consultations between BOEM, BSEE,
and the NANA Regional Corporation
and the Cully Corporation (ANCSA
Village Corporation) from Point Lay.
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Among the most frequent input DOI
received through listening sessions and
tribal consultation were comments
relating to impacts on, and protection
of, subsistence hunting and fishing areas
and species, including consideration of
mammal and fish migratory patterns,
hunting and fishing seasons, and
impacts of pollutants and equipment
movements. Concerns also included the
relative lack of infrastructure, such as
roads, housing, and equipment, in
coastal communities near proposed
Arctic OCS oil and gas exploration
areas, and inclusion of local Alaska
Natives in monitoring and other
activities. Commenters also requested
that we incorporate traditional
knowledge of the Arctic OCS into our
decision-making for proposed
regulations. We reviewed all comments
received to date and have, where
appropriate, crafted proposed measures
to address Alaska Native concerns. DOI
intends to continue consultation with
affected tribes and ANCSA Corporations
following publication of the proposed
rule.
J. E.O. 12898
E.O. 12898 requires Federal agencies
to make achieving environmental justice
part of their mission by identifying and
addressing disproportionately high and
adverse human health or environmental
effects of their programs, policies, and
activities on minority populations and
low-income populations in the U.S. DOI
has determined that this proposed rule
does not have a disproportionately high
or adverse human health or
environmental effect on native,
minority, or low-income communities
because its provisions are designed to
increase environmental protection and
minimize any impact of exploration
drilling on subsistence hunting
activities and Alaska Native community
resources and infrastructure.
K. Paperwork Reduction Act (PRA)
This rule contains new information
collection (IC) requirements for both
BOEM and BSEE regulations, and a
submission under the PRA is required.
Therefore, an IC request for each Bureau
is being submitted to OMB for review
and approval under 44 U.S.C. 3501 et
seq. The PRA provides that an agency
may not conduct or sponsor, and a
person is not required to respond to, an
IC unless it displays a currently valid
OMB control number. The IC aspects
affecting each Bureau are discussed
separately. Instructions on how to
comment follow those discussions.
BOEM Information Collection—30 CFR
Part 550
This proposed rule adds new
requirements for submitting EPs and
other information before conducting oil
and gas exploration drilling activities on
the Arctic OCS. The title of the
collection for the rulemaking is 30 CFR
550, Subpart B, Arctic OCS Activities—
New. The burdens for the current
planning requirements under 30 CFR
550, Subpart B, regulations are
approved by OMB under Control
Number 1010–0151 (190,480 hours,
$3,713,665 non-hour costs; expiration
12/31/14; current collection can be
viewed at www.reginfo.gov/public/).
When final regulations become
effective, the new IC burdens for this
rulemaking will be consolidated into the
existing collection for Subpart B.
Respondents for this rulemaking are
Federal oil, gas, or sulphur lessees and/
or operators on the Arctic OCS.
Submissions are mandatory and
generally on occasion. BOEM collects
the information to ensure that planned
operations will be safe; will not
adversely affect the marine, coastal, or
human environments; will respond to
the special conditions on the Arctic
OCS; and will conserve the resources of
the Arctic OCS. BOEM uses the
information to ensure, through
advanced planning, that operators are
capable of safely operating in the unique
environmental conditions of the Arctic
and to make informed decisions on
whether to approve EPs as submitted or
whether modifications are necessary.
BOEM also plans to share the
preliminary information submitted in
the IOP with other relevant agencies to
provide them the opportunity to engage
in constructive dialogue/feedback with
operators, and each other, early in the
process.
The proposed rule adds new
requirements under § 550.204 for
operators to develop an IOP for each
exploratory drilling program on the
Arctic OCS, and to submit it to BOEM
at least 90 days in advance of filing their
EP. The IOP addresses all phases of the
operator’s proposed Arctic exploration
drilling activities at a strategic or
conceptual level, showing how
operations will be designed, executed,
and managed as an integrated endeavor
from start to finish.
The proposed rule also revises the IC
for plans submission by expanding the
requirements under § 550.220 to address
the specific conditions (e.g., ice
management procedures) associated
with oil and gas activity on the Arctic
OCS. The rule provisions are intended
to ensure that operators on the Arctic
OCS design and conduct their
exploration drilling activities in a
manner suitable for the area’s unique
conditions.
BOEM estimates that the new
requirements will add a total of 270
burden hours to the already approved
burdens for plans. Because not all EPs
submitted to BOEM will involve Arctic
OCS exploration drilling, we are
separating the Arctic-specific
requirements and burdens from the
national EP requirements. The burden
table that follows this paragraph
outlines the new and expanded
requirements and burdens associated
with this rulemaking. BOEM has not
identified any non-hour cost burdens
associated with these requirements.
BURDEN BREAKDOWN
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Citation 30 CFR Part 550 Subpart B
Reporting & Recordkeeping Requirement
Hour burden
Average
number of
annual responses
Burden
hours
Arctic Integrated Operations Plan (IOP)
New 2041 ...................................
For New Arctic OCS Exploration Activities: Submit IOP, including
all required information.
90
2
180
Burdens already covered
under plans in 1010–0151.
0
Contents of Exploration Plans (EP)
206 .............................................
220 .............................................
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General requirements for plans. .....................................................
Submit Alaska-specific information. ................................................
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BURDEN BREAKDOWN—Continued
Average
number of
annual responses
Citation 30 CFR Part 550 Subpart B
Reporting & Recordkeeping Requirement
Expanded 220 ............................
For New Arctic OCS Exploration Activities: Submit required Arctic-specific information with EP, including confirmations.
For Existing Arctic OCS Exploration Activities: Revise and resubmit Arctic-specific information, as required.
15
2
30
30
2
60
.........................................................................................................
....................
6
270
Expanded 220 ............................
Total Burden for Proposed
Rule.
Hour burden
Burden
hours
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1 Industry already compiles this information internally for planning and contract oversight; therefore, the burden expected is minimal, just to prepare and submit to BOEM.
BSEE Information Collection—30 CFR
Parts 250 and 254
The title of the collection of
information for this rule is 30 CFR part
250, subparts A, D, S and 30 CFR part
254, Arctic Oil & Gas Exploratory
Drilling Operations—New. The
proposed regulations establish
requirements for safe, responsible, and
environmentally protective Arctic OCS
oil and gas exploration, and the
information is used in our efforts to
protect life and the environment,
conserve natural resources, and prevent
waste.
Potential respondents comprise
Federal OCS oil, gas, and sulphur
operators and lessees on the Arctic OCS.
The frequency of response varies
depending upon the requirement.
Responses to this collection of
information are mandatory; they are
submitted on occasion, annually, or as
a result of situations encountered,
depending upon the requirement. The
IC does not include questions of a
sensitive nature. BSEE will protect
proprietary information according to the
Freedom of Information Act (5 U.S.C.
552) and DOI’s implementing
regulations (43 CFR part 2), 30 CFR part
252, and 30 CFR 250.197, which address
disclosure of data and information to be
made available to the public.
As discussed earlier in the preamble,
the proposed rule encompasses multiple
subparts and focuses on Arctic OCS
exploratory drilling activities and
related operations. This proposed rule
revises several existing collections
under BSEE regulations. The
requirements and burdens for these
regulations are currently approved by
OMB under 30 CFR part 250, subpart A,
1014–0022, expiration 8/3/2017 (84,391
hours, $1,371,458 non-hour cost
burdens); subpart D, 1014–0018,
expiration 10/31/17 (102,512 hours);
subpart S, 1014–0017, expiration 3/31/
16 (651,728 hours, $9,444,000 non-hour
cost burdens); and 30 CFR part 254,
1014–0007, expiration 12/31/2015
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(60,198 hours); current collections can
be viewed at www.reginfo.gov/public/.
When final regulations are promulgated,
the new IC burdens for these subparts/
parts will be incorporated into the
respective collections of information for
those regulations.
The following table provides a
breakdown of the paperwork and nonhour cost burdens for this proposed
rule. For the current requirements
retained in the proposed rule, we used
the OMB approved estimated hour and
non-hour cost burdens, where
discernible. However, there are several
new requirements in the proposed rule
as follows:
1. Subpart A:
In § 250.188(c), we have added
immediate oral reporting of anysea ice
movement/conditions, start and
termination of ice management
activities, or kicks or unexpected
operational issues, and submission of a
written report within 24 hours after
completing ice management activities
(+11 hours).
2. Subpart D:
In § 250.452(a) and (b), we have added
real-time data gathering, monitoring,
and storing related to the BOP control
system, fluid handling, and downhole
conditions, etc.; notify BSEE of location
of data; make data available to BSEE
upon request (+288 hours).
In § 250.470, we have added
information requirements including, but
not limited to, detailed descriptions of:
Environmental, meteorologic, and
oceanic conditions expected at well
site(s), and, how drilling units and
equipment will be prepared for service;
transitioning rig from being underway to
drilling and vice versa, along with
anticipated repair and maintenance
plans; specific drilling objectives,
timelines, and updated contingency
plans for temporary abandonment;
weather and ice forecasting and
management; compliance with relief
well rig requirements; SCCE
capabilities, including, but not limited
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to, submit equipment statement
showing capable of controlling WCD,
explanation of your or your contractor’s
SCCE capabilities; inventory of supplies
and services, along with relevant
supplier information; proof of contracts
or membership agreements to provide
SCCE or supplies, services; description
of procedures for inspecting, testing,
and maintaining SCCE; how all
personnel operating SCCE received
training to deploy and operate—
including dates of prior and planned
training; and how the operator
incorporated API RP 2N, Third Edition,
into its planned drilling operations
(+324 hours).
In § 250.471(c), (e), and (f), we
propose to add requirements that
operators: Submit a reevaluation of
SCCE capabilities, including any new
WCD rate, and demonstrate compliance
with proposed § 250.470(f); maintain all
SCCE inspection and maintenance
records for at least 10 years; make
records available to BSEE upon request;
maintain all records relating to use of
SCCE during testing, training, and
deployment activities for at least 3
years; and make records available to
BSEE upon request (+100 hours).
In § 250.472(c), we propose to add a
provision stating that operators may
request approval for alternative
compliance measures for relief rig
requirements in accordance with
existing § 250.141 (+0 hours).
3. Subpart S:
In § 250.1920(b), (c), (d), and (e), the
additional non-hour cost burdens
pertaining to Audit Service Provider
(ASP) audits every year in the Arctic in
which exploration drilling is conducted
would apply (+$129,000 non-hour cost).
4. 30 CFR part 254:
Operators currently submit
information with their spill response
plans (§§ 254.20–29) that is related to
the requirements in this rulemaking
under proposed §§ 254.70, 254.80, and
254.90; therefore, we believe that the
current burden sufficiently covers the
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proposed modifications. We have added
a new requirement in § 254.80(c) for
submitting a description of the system
used to maintain real time monitoring
(+12 hours).
BURDEN TABLE
Citation 30 CFR parts
250 and 254
Reporting and recordkeeping requirements
Hour burden
Average number of
annual responses
Annual burden hours
30 CFR Part 250, Subpart A
188(c); 190 .....................
188(c); 190 .....................
Subtotal ...................
NEW—Provide BSEE immediate oral report of sea ice movement/conditions;
start and termination of ice management
activities; kicks or unexpected operational issues.
NEW—Submit a written report within 24
hours after completing ice management
activities.
Oral 1.5 .....................
2 notifications ..............
3.
Written 4 ...................
2 reports .....................
8.
......................................................................
...................................
4 responses ................
11 hours.
30 CFR Part 250, Subpart D
418 ..................................
Additional information that is to be submitted with an APD is covered under the specific requirement listed in this burden table under 30 CFR 250.470.
NEW—Immediately transmit real-time data 12 .............................. 1 transmittal ................
gathering and monitoring to record,
store, and transmit data relating to the
BOP control system, fluid handling,
downhole conditions; prior to well operations, notify BSEE of monitoring location and make data available to BSEE
upon request.
NEW—Store and monitor all information re- 1 ................................ 2 wells × 138 drilling
lating to § 250.452(a); make data availdays = 276.
able to BSEE upon request.
0.
452(b) .............................
Store and retain all monitoring records per
requirements of §§ 250.466 and 467.
0.
470(a); 417; 418 .............
NEW—Submit detailed descriptions of environmental, meteorologic, and oceanic
conditions expected at well site(s); how
drilling unit, equipment, and materials will
be prepared for service; how the drilling
unit will be in compliance with § 250.417.
NEW—Submit detailed description of
transitioning rig from being underway to
drilling and vice versa.
NEW—Submit detailed description of any
anticipated repair and maintenance plans
for the drilling unit and equipment.
NEW—Submit well specific drilling objectives, timelines, and updated contingency
plans etc., for temporary abandonment.
NEW—Submit detailed description concerning weather and ice forecasting for
all phases; including how to ensure continuous awareness of weather/ice hazards at/between each well site; plans for
managing ice hazards and responding to
weather events; verification of capabilities.
NEW—Submit a detailed description of
compliance with relief rig plans.
452(a), (b) .......................
452(b) .............................
470(b); 418 .....................
470(b); 418 .....................
470(c); 418 .....................
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470(d); 418 .....................
470(e); 418; 472 .............
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Burden covered under 30 CFR 250, Subpart
D, 1014–0018.
12.
276.
10 ..............................
1 submittal ..................
10.
4 ................................
16.
2 ................................
2 each well—underway to drilling; drilling to underway = 4.
2 submittals ................
4.
4 ................................
2 submittals ................
8.
6 ................................
1 submittal ..................
6.
140 ............................
1 explanation ..............
140.
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9963
BURDEN TABLE—Continued
Citation 30 CFR parts
250 and 254
Reporting and recordkeeping requirements
Hour burden
Average number of
annual responses
470(f); 471(c); 418 ..........
NEW—SCCE capabilities; submit equipment statement showing capable of controlling WCD; detailed description of your
or your contractor’s SCCE capabilities including operating assumptions and limitations; inventory of local and regional
supplies and services, along with supplier relevant information; proof of contract or agreements for providing SCCE
or supplies, services; detailed description
of procedures for inspecting, testing, and
maintaining SCCE; and detailed description of your plan ensuring all members of
the team operating SCCE have received
training to deploy and operate, include
dates of prior and planned training.
NEW—Submit a detailed description of utilizing best practices of API RP 2N during
operations.
NEW—Submit with your APM, a reevaluation of your SCCE capabilities if well design changes; include any new WCD
rate and demonstrate that your SCCE
capabilities will comply with § 250.470(f).
NEW—Maintain all SCCE testing, inspection, and maintenance records for at
least 10 years; make available to BSEE
upon request.
NEW—Maintain all records pertaining to
use of SCCE during testing, training, and
deployment activities for at least 3 years;
make available to BSEE upon request.
60 ..............................
2 submittals ................
120.
20 ..............................
1 submittal ..................
20.
10 ..............................
2 submittals ................
20.
20 ..............................
2 records .....................
40.
20 ..............................
2 records .....................
40.
472(c) .............................
Request approval for alternative compliance for relief rig requirements.
Burden covered under 30 CFR 250, Subpart A,
1014–0022
0.
Subtotal ...................
......................................................................
...................................
712 hours
470(g); 418 .....................
471(c); 470(f); 465(a) .....
471(e) .............................
471(f) ..............................
297 responses ............
Annual burden hours
30 CFR Part 250, Subpart S
1 operator × $129,000 audit for high activity = $129,000.
1920(b), (c), (e) ..............
ASP audit for High Activity Operator ..........
NOTE: An audit once every 3 years in
POCSR and GOMR; an audit in the Arctic in every year in which drilling is conducted.
1920(c) ...........................
Submit to BSEE after completed audit, an
audit report of findings and conclusions,
including deficiencies and required supporting information/documentation.
Burden covered under 30 CFR 250, Subpart S,
1014–0017.
1920(d) ...........................
Submit/resubmit a copy of your CAP that
will address deficiencies identified in
audit.
.
Subtotal ...................
......................................................................
...................................
1 response ..................
0
0
$129,000 Non Hour Cost Burdens.
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30 CFR Part 254, Subpart E
55; 70; 80; 90 .................
Submit spill response plan for OCS facilities with all information required in regulations and related documents.
80(c) ...............................
NEW—Submit a description of system
used to maintain real-time location tracking for all response resources.
90(a) ...............................
Include in your training and exercise activities the requirements of this section.
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Burden covered under 30 CFR 254, 1014–
0007.
6 ................................
2 descriptions .............
Burden covered under 30 CFR 254, 1014–
0007.
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12.
0.
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BURDEN TABLE—Continued
Citation 30 CFR parts
250 and 254
Reporting and recordkeeping requirements
Hour burden
Average number of
annual responses
90(b) ...............................
Notify BSEE 60 days prior to handling,
storing, or transporting oil.
Subtotal ...................
Total Hour Burden ...
......................................................................
......................................................................
...................................
...................................
2 responses ................
304 Responses ...........
......................................................................
...................................
Annual burden hours
12 hours.
735 Hours.
$129,000 Non-Hour Cost Burdens.
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
Note: For FY 2015, we calculated the burden with 2 rigs (same operator), each rig drilling 1 well.
Commenting on Information Collections
As part of our continuing effort to
reduce paperwork and respondent
burdens, BOEM and BSEE invite the
public to comment on any aspect of the
reporting and recordkeeping burdens. If
you wish to comment on the IC aspects
of these regulations, you may send your
comments directly to by email to OMB
(OIRA_submission@omb.eop.gov) or by
fax 202–395–5806, with a copy to BSEE
(see Addresses section). Please identify
your comments with RIN: 1082–AA01.
To see a copy of either IC request
submitted to OMB, go to
www.reginfo.gov (select Information
Collection Review, Currently Under
Review). You may obtain a copy of the
supporting statement for the new IC by
contacting each Bureau’s Information
Collection Clearance Officer: Cheryl
Blundon, BSEE, (703) 787–1607, and
Arlene Bajusz, BOEM, (703) 787–1025.
The OMB is required to make a
decision concerning the ICs contained
in these proposed regulations between
30 and 60 days after publication of this
document in the Federal Register.
Therefore, a comment to OMB is best
assured of having its full effect if OMB
receives it by March 26, 2015.
BOEM and BSEE specifically solicit
comments on the following questions:
1. Is the proposed collection of
information necessary for the Bureaus to
properly perform their functions, and
will it be useful?
2. Are the estimates of the burden
hours of the proposed collection
reasonable?
3. Do you have any suggestions that
would enhance the quality, clarity, or
usefulness of the information to be
collected?
4. Is there a way to minimize the IC
burden on those who are to respond,
including through the use of appropriate
automated electronic, mechanical, or
other forms of information technology?
In addition, the PRA requires agencies
to estimate the total annual reporting
and recordkeeping non-hour cost
burden resulting from the collection of
information. BSEE has identified one
non-hour cost burden in the BSEE
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22:02 Feb 23, 2015
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Burden Table. We solicit your
comments on any non-hour costs. For
reporting and recordkeeping only, your
response should split the cost estimate
into two components: (1) Total capital
and startup cost component and (2)
annual operation, maintenance, and
purchase of services component.
Your estimates should consider the
costs to generate, maintain, and disclose
or provide the information. You should
describe the methods you use to
estimate major cost factors, including
system and technology acquisition,
expected useful life of capital
equipment, discount rate(s), and the
period over which you incur costs.
Generally, your estimates should not
include equipment or services
purchased: (1) Before October 1, 1995;
(2) to comply with requirements not
associated with the IC; (3) for reasons
other than to provide information or
keep records for the Government; or (4)
as part of customary and usual business
or private practices.
L. National Environmental Policy Act of
1969 (NEPA)
BOEM and BSEE developed a draft
Environmental Assessment (EA) to
determine whether this proposed rule
would have a significant impact on the
quality of the human environment
under the NEPA. The draft EA is
available for review and public
comment in conjunction with this
proposed rule at www.regulations.gov
(in the Search box, enter BSEE–2013–
0011).
M. Data Quality Act
In developing this rule, we did not
conduct or use a study, experiment, or
survey requiring peer review under the
Data Quality Act (Pub. L. 106–554, app.
C § 515, 114 Stat. 2763, 2763A–153–
154).
N. Effects on the Nation’s Energy Supply
(E.O. 13211)
Although this proposed rule is a
significant regulatory action under E.O.
12866, it is not a significant energy
action under the definition of that term
in E.O. 13211 because:
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1. It is not likely to have a significant
adverse effect on the supply,
distribution or use of energy; and
2. It has not been designated as a
significant energy action by the
Administrator of OIRA.
Thus, a Statement of Energy Effects is
not required.
Due to the inherent practical
difficulties of exploration and
production in the area, to date there has
been relatively little exploration
activity, and very little production of oil
and gas, on the Arctic OCS. The only
existing oil production from the Arctic
OCS is through the Northstar Island
facility. Since the proposed rule does
not apply to development or production
activities, it would not reduce or inhibit
production of oil and gas and would
have no adverse impact on oil and gas
supplies or prices.
O. Clarity of this Regulation
We are required by E.O. 12866, E.O.
12988, and by the Presidential
Memorandum of June 1, 1998, to write
all rules in plain language. This means
that each rule we publish must:
1. Be logically organized;
2. Use the active voice to address
readers directly;
3. Use clear language rather than
jargon;
4. Be divided into short sections and
sentences; and
5. Use lists and tables wherever
possible.
If you believe we have not met these
requirements, send us comments by one
of the methods listed in the ADDRESSES
section. To better help us revise the
rule, your comments should be as
specific as possible. For example, you
should tell us the numbers of the
sections or paragraphs that you find
unclear, which sections or sentences are
too long, or the sections where you
believe lists or tables would be useful.
P. Public Availability of Comments
BOEM and BSEE encourage you to
participate in this proposed rule by
submitting written comments as
discussed in the ADDRESSES and DATES
sections of this proposed rule. Before
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including your address, phone number,
email address or other personal
identifying information in your
comment on this proposed rule, you
should be aware that your entire
comment—including your personal
identifying information—may be made
publicly available at any time. While
you can ask us in your comment to
withhold your personal identifying
information from public review, we
cannot guarantee that we will be able to
do so.
List of Subjects
30 CFR Part 250
30 CFR Part 254
Continental shelf, Intergovernmental
relations, Oil and gas exploration, Oil
pollution, Pipelines, Public lands—
mineral resources, Reporting and
recordkeeping requirements.
30 CFR Part 550
Administrative practice and
procedure, Environmental impact
statements, Environmental protection,
Federal lands, Government contracts,
Oil, Oil and gas exploration, Oil and gas
development, Outer continental shelf,
Penalties, Pipelines, Public lands—
mineral resources, Public lands—rightof-way, Reporting and recordkeeping
requirements, Sulphur development and
production, Energy, Oil and gas
reserves, Natural gas, Natural resources,
Continental shelf, Offshore structures,
Petroleum, Bonds, Surety bonds.
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
Dated: February 18, 2015.
Janice M. Schneider,
Assistant Secretary, Land and Minerals
Management.
For the reasons stated in the
preamble, BOEM and BSEE amend 30
CFR parts 250, 254, and 550 as follows:
TITLE 30—MINERAL RESOURCES
CHAPTER II—BUREAU OF SAFETY AND
ENVIRONMENTAL ENFORCEMENT,
DEPARTMENT OF THE INTERIOR
PART 250—OIL AND GAS AND SULPHUR
OPERATIONS IN THE OUTER CONTINENTAL
SHELF
20:32 Feb 23, 2015
Authority: 30 U.S.C. 1751, 31 U.S.C. 9701,
33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334.
2. Amend § 250.105 by:
a. Revising the definition of ‘‘District
Manager’’ and
■ b. Adding new definitions for ‘‘Arctic
OCS’’, ‘‘Arctic OCS conditions’’, ‘‘Cap
and flow system’’, ‘‘Capping stack’’,
‘‘Containment dome’’ and ‘‘Source
control and containment equipment
(SCCE)’’ in alphabetical order, to read as
follows:
■
■
§ 250.105
Continental shelf, Environmental
impact statements, Environmental
protection, Government contracts,
Incorporation by reference,
Investigations, Mineral royalties, Oil
and gas development and production,
Oil and gas exploration, Oil and gas
reserves, Penalties, Pipelines, Public
lands—mineral resources, Public
lands—rights of-way, Reporting and
recordkeeping requirements, Sulphur
development and production, Sulphur
exploration, Surety bonds.
VerDate Sep<11>2014
1. The authority citation for 30 CFR
part 250 is revised to read as follows:
■
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Definitions.
*
*
*
*
*
Arctic OCS means the Beaufort Sea
and Chukchi Sea Planning Areas, as
described in the Proposed Final OCS Oil
and Gas Leasing Program for 2012–2017
(June 2012).
Arctic OCS conditions means, for the
purposes of this part, the conditions
operators can reasonably expect during
operations on the Arctic OCS. Such
conditions, depending on the time of
year, include, but are not limited to:
Extreme cold, freezing spray, snow,
extended periods of low light, strong
winds, dense fog, sea ice, strong
currents, and dangerous sea states.
Remote location, relative lack of
infrastructure, and the existence of
subsistence hunting and fishing areas
are also characteristic of the Arctic
region.
*
*
*
*
*
Cap and flow system means an
integrated suite of equipment and
vessels, including a capping stack and
associated flow lines, that, when
installed or positioned, is used to
control the flow of fluids escaping from
the well by conveying the fluids to the
surface to a vessel or facility equipped
to process the flow of oil, gas, and
water. A cap and flow system is a high
pressure system that includes the
capping stack and piping necessary to
convey the flowing fluids through the
choke manifold to the surface
equipment.
Capping stack means a mechanical
device that can be installed on top of a
subsea or surface wellhead or blowout
preventer to stop the uncontrolled flow
of fluids into the environment.
*
*
*
*
*
Containment dome means a nonpressurized container that can be used
to collect fluids escaping from the well
or equipment below the sea surface or
from seeps by suspending the device
over the discharge or seep location. The
containment dome includes all of the
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9965
equipment necessary to capture and
convey fluids to the surface.
*
*
*
*
*
District manager means the BSEE
officer with authority and responsibility
for operations or other designated
program functions for a district within
a BSEE Region. For activities on the
Alaska OCS, any reference in this part
to District Manager means the BSEE
Regional Supervisor.
*
*
*
*
*
Source control and containment
equipment (SCCE) means the capping
stack, cap and flow system, containment
dome, and/or other subsea and surface
devices, equipment, and vessels whose
collective purpose is to control a spill
source and stop the flow of fluids into
the environment or to contain fluids
escaping into the environment. ‘‘Surface
devices’’ refers to equipment mounted
or staged on a barge, vessel, or facility
to separate, treat, store and/or dispose of
fluids conveyed to the surface by the
cap and flow system or the containment
dome. ‘‘Subsea devices’’ includes, but is
not limited to, remotely operated
vehicles, anchors, buoyancy equipment,
connectors, cameras, controls and other
subsea equipment necessary to facilitate
the deployment, operation and retrieval
of the SCCE. The SCCE does not include
a blowout preventer.
*
*
*
*
*
■ 3. Amend § 250.188 by adding a new
paragraph (c) to read as follows:
§ 250.188 What incidents must I report to
BSEE and when must I report them?
*
*
*
*
*
(c) On the Arctic OCS, in addition to
the requirements of paragraphs (a) and
(b) of this section, you must provide to
the BSEE inspector on location, if one
is present, or to the Regional Supervisor
both of the following:
(1) An immediate oral report if any of
the following occur:
(i) Any sea ice movement or condition
that has the potential to affect your
operation or trigger ice management
activities;
(ii) The start and termination of ice
management activities; or
(iii) Any ‘‘kicks’’ or operational issues
that are unexpected and could result in
the loss of well control.
(2) Within 24 hours after completing
ice management activities, a written
report of such activities that conforms to
the content requirements in § 250.190.
■ 4. Amend § 250.198 by adding
paragraph (h)(89) to read as follows:
§ 250.198 Documents incorporated by
reference.
*
*
*
(h) * * *
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*
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(89) API RP 2N, Third Edition,
‘‘Recommended Practice for Planning,
Designing, and Constructing Structures
and Pipelines for Arctic Conditions;’’
incorporated by reference at
§ 250.470(g);
*
*
*
*
*
■ 5. Amend § 250.300 by revising
paragraphs (b)(1) and (b)(2) to read as
follows:
§ 250.300
Pollution prevention.
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
*
*
*
*
*
(b)(1) The District Manager may
restrict the rate of drilling fluid
discharges or prescribe alternative
discharge methods. The District
Manager may also restrict the use of
components which could cause
unreasonable degradation to the marine
environment. No petroleum-based
substances, including diesel fuel, may
be added to the drilling mud system
without prior approval of the District
Manager. For Arctic OCS exploratory
drilling, you must capture all
petroleum-based mud to prevent its
discharge into the marine environment.
The Regional Supervisor may also
require you to capture, during your
Arctic OCS exploratory drilling
operations, all water-based mud from
operations after completion of the hole
for the conductor casing to prevent its
discharge into the marine environment,
based on various factors including, but
not limited to:
(i) The proximity of your exploratory
drilling operation to subsistence
hunting and fishing locations;
(ii) The extent to which discharged
mud may cause marine mammals to
alter their migratory patterns in a
manner that impedes subsistence users’
access to, or use of, those resources, or
increases the risk of injury to
subsistence users; or
(iii) The extent to which discharged
mud may adversely affect marine
mammals, fish, or their habitat.
(2) Approval of the method of
disposal of drill cuttings, sand, and
other well solids shall be obtained from
the District Manager. For Arctic OCS
exploratory drilling, you must capture
all cuttings from operations that utilize
petroleum-based mud to prevent their
discharge into the marine environment.
The Regional Supervisor may also
require you to capture, during your
Arctic OCS exploratory drilling
operations, all cuttings from operations
that utilize water-based mud after
completion of the hole for the conductor
casing to prevent their discharge into
the marine environment, based on
various factors including, but not
limited to:
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20:32 Feb 23, 2015
Jkt 235001
(i) The proximity of your exploratory
drilling operation to subsistence
hunting and fishing locations;
(ii) The extent to which discharged
cuttings may cause marine mammals to
alter their migratory patterns in a
manner that impedes subsistence users’
access to, or use of, those resources, or
increases the risk of injury to
subsistence users; or
(iii) The extent to which discharged
cuttings may adversely affect marine
mammals, fish, or their habitat.
*
*
*
*
*
■ 6. Amend § 250.402 by adding a new
paragraph (c) to read as follows:
§ 250.402
well?
When and how must I secure a
*
*
*
*
*
(c) For Arctic OCS exploratory
drilling operations, in addition to the
requirements of paragraphs (a) and (b) of
this section:
(1) If you move your drilling rig off a
well prior to completion or permanent
abandonment, you must ensure that any
equipment left on, near, or in a well
bore that has penetrated below the
surface casing is positioned in a manner
to:
(i) Protect the well head; and
(ii) Prevent or minimize the
likelihood of compromising the downhole integrity of the well or the
effectiveness of the well plugs.
(2) In areas of ice scour, you must use
a well mudline cellar or an equivalent
means of minimizing the risk of damage
to the well head.
■ 7. Amend § 250.418 by adding a new
paragraph (k) to read as follows:
§ 250.418 What additional information
must I submit with my APD?
*
*
*
*
*
(k) For Arctic OCS exploratory
drilling operations, you must provide
the information required by § 250.470.
■ 8. Amend § 250.447 by revising
paragraph (b) to read as follows:
§ 250.447 When must I pressure test the
BOP system?
*
*
*
*
*
(b) Before 14 days have elapsed since
your last BOP pressure test, or for Arctic
OCS exploratory drilling operations
before 7 days have elapsed since your
last BOP pressure test. You must begin
to test your BOP system before midnight
on the 14th day (or for Arctic OCS
exploratory drilling operations, the 7th
day) following the conclusion of the
previous test. However, the District
Manager may require more frequent
testing if conditions or BOP
performance warrant; and
*
*
*
*
*
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9. Add new § 250.452 to read as
follows:
■
§ 250.452 What are the real-time
monitoring requirements for Arctic OCS
exploratory drilling operations?
(a) When conducting exploratory
drilling operations on the Arctic OCS,
you must have real-time data gathering
and monitoring capability to record,
store, and transmit data regarding all
aspects of:
(1) The BOP control system;
(2) The well’s fluid handling systems
on the rig; and
(3) The well’s downhole conditions as
monitored by a downhole sensing
system, when such a system is installed.
(b) During well operations, you must
immediately transmit the data identified
in paragraph (a) of this section to a
designated onshore location where it
must be stored and monitored by
qualified personnel who have the
capability for continuous contact with
rig personnel and who have the
authority, in consultation with rig
personnel, to initiate any necessary
action in response to abnormal data or
events. Prior to well operations, you
must notify BSEE where the data will be
monitored during those operations, and
you must make the data available to
BSEE, including in real time, upon
request. After well operations, you must
store the data at a designated location
for recordkeeping purposes as required
in §§ 250.466 and 250.467.
■ 10. Add new undesignated centered
heading ‘‘ADDITIONAL ARCTIC OCS
REQUIREMENTS’’ and §§ 250.470
through 250.473 in Subpart D to read as
follows:
Additional Arctic OCS Requirements
§ 250.470 What additional information
must I submit with my APD for Arctic OCS
exploratory drilling operations?
In addition to all other applicable
requirements included in this part, you
must provide with your APD all of the
following information pertaining to your
proposed Arctic OCS exploratory
drilling:
(a) A detailed description of:
(1) The environmental, and
meteorologic and oceanic conditions
you expect to encounter at the well
site(s);
(2) How your equipment, materials,
and drilling unit will be prepared for
service in the conditions in paragraph
(a)(1) of this section, and how your
drilling unit will be in compliance with
the requirements of § 250.417.
(b) A detailed description of all
operations necessary in Arctic OCS
Conditions to transition the rig from
being under way to conducting drilling
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operations and from ending drilling
operations to being under way, as well
as any anticipated repair and
maintenance plans for the drilling unit
and equipment. The description should
include, but not be limited to:
(1) Recovering the subsea equipment,
including the marine riser and the lower
marine riser package;
(2) Recovering the BOP;
(3) Recovering the auxiliary sub-sea
controls and template;
(4) Laying down the drill pipe and
securing the drill pipe and marine riser;
(5) Securing the drilling equipment;
(6) Transferring the fluids for
transport or disposal;
(7) Securing ancillary equipment like
the draw works and lines;
(8) Refueling or transferring fuel;
(9) Offloading waste;
(10) Recovering the ROVs;
(11) Picking up the oil spill
prevention booms and equipment; and
(12) Offloading the drilling crew.
(c) Well-specific drilling objectives,
timelines, and updated contingency
plans for temporary abandonment of the
well, including but not limited to the
following:
(1) When you will spud the particular
well (i.e., begin drilling operations at the
well site) identified in the APD;
(2) How long you will take to drill the
well;
(3) Anticipated depths and geologic
targets, with timelines;
(4) When you expect to set and
cement each string of casing;
(5) When and how you would log the
well;
(6) Your plans to test the well;
(7) When and how you intend to
abandon the well, including specifically
addressing your plans for how to move
the rig off location and how you will
meet the requirements of § 250.402(c);
(8) A description of what equipment
and vessels will be involved in the
process of temporarily abandoning the
well due to ice; and
(9) An explanation of how these
elements will be integrated into your
overall program.
(d) A detailed description of your
weather and ice forecasting capability
for all phases of the drilling operation,
including:
(1) How you will ensure continuous
awareness of potential weather and ice
hazards at, and during transition
between, wells;
(2) Your plans for managing ice
hazards and responding to weather
events; and
(3) Verification that you have the
capabilities described in your BOEMapproved EP.
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20:32 Feb 23, 2015
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(e) A detailed description of how you
will comply with the requirements of
§ 250.472.
(f) A statement that you own, or have
a contract with a provider for, source
control and containment equipment
(SCCE) that is capable of controlling
and/or containing a worst case
discharge, as described in your BOEMapproved EP, when proposing to use a
MODU to conduct exploratory drilling
operations on the Arctic OCS. The
following information must be included
in your SCCE submittal:
(1) A detailed description of your or
your contractor’s SCCE capabilities,
including operating assumptions and
limitations, reflecting that you have
access to, and the ability to deploy in
accordance with § 250.471, all SCCE
necessary to regain control of the well,
including the ability to evaluate the
performance of the well design to
determine how a full shut-in can be
achieved without having reservoir fluids
discharged into the environment;
(2) An inventory of the local and
regional SCCE, supplies, and services
that you own or for which you have a
contract with a provider. You must
identify each supplier of such
equipment and services and provide
their locations and telephone numbers;
(3) Where applicable, proof of
contracts or membership agreements
with cooperatives, service providers, or
other contractors that will provide you
with the necessary SCCE or related
supplies and services if you do not
possess them. The contract or
membership agreement must include
provisions for ensuring the availability
of the personnel and/or equipment on a
24-hour per day basis while you are
drilling below or working below the
surface casing;
(4) A detailed description of the
procedures for inspecting, testing, and
maintaining your SCCE; and
(5) A detailed description of your plan
to ensure that all members of your
operating team who are responsible for
operating the SCCE have received the
necessary training to deploy and operate
such equipment in Arctic OCS
Conditions and demonstrate ongoing
proficiency in source control operations.
You must also identify and include the
dates of prior and planned training.
(g) Where it does not conflict with
other requirements of this subpart, and
except as provided below, you must
comply with the requirements of API RP
2N, Third Edition ‘‘Planning, Designing,
and Constructing Structures and
Pipelines for Arctic Conditions’’
(incorporated by reference as specified
in § 250.198), and provide a detailed
description of how you will utilize the
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9967
best practices included in API RP 2N
during your exploratory drilling
operations. You are not required to
incorporate the following sections of
API RP 2N into your drilling operations:
(1) Sections 6.6.3 through 6.6.4;
(2) The foundation recommendations
in Section 8.4;
(3) Section 9.6;
(4) The recommendations for
permanently moored systems in Section
9.7;
(5) The recommendations for pile
foundations in Section 9.10;
(6) Section 12;
(7) Section 13.2.1;
(8) Sections 13.8.1.1, 13.8.2.1,
13.8.2.2, 13.8.2.4 through 13.8.2.7;
(9) Sections 13.9.1, 13.9.2, 13.9.4
through 13.9.8;
(10) Sections 14 through 16; and
(11) Section 18.
§ 250.471 What are the requirements for
Arctic OCS source control and
containment?
You must meet the following
requirements for all exploration wells
drilled on the Arctic OCS:
(a) If you use a MODU when drilling
below or working below the surface
casing, you must have access to:
(1) A capping stack, positioned to
ensure that it will arrive at the well
location within 24 hours after a loss of
well control and can be deployed as
directed by the Regional Supervisor
pursuant to paragraph (h) of this
section;
(2) A cap and flow system, positioned
to ensure that it will arrive at the well
location within 7 days after a loss of
well control and can be deployed as
directed by the Regional Supervisor
pursuant to paragraph (h) of this
section. The cap and flow system must
be designed to capture at least the
amount of hydrocarbons equivalent to
the calculated worst case discharge rate
referenced in your BOEM-approved EP;
and
(3) A containment dome, positioned
to ensure that it will arrive at the well
location within 7 days after a loss of
well control and can be deployed as
directed by the Regional Supervisor
pursuant to paragraph (g) of this section.
The containment dome must have the
capacity to pump fluids without relying
on buoyancy.
(b) You must conduct a monthly
stump test of dry-stored capping stacks.
If you use a pre-positioned capping
stack, you must conduct a stump test
prior to each installation on each well.
(c) As required by § 250.465(a), if you
propose to change your well design, you
must submit an APM. For Arctic OCS
operations, your APM must include a
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reevaluation of your SCCE capabilities
for any new WCD rate, and a
demonstration that your SCCE
capabilities will meet the criteria in
§ 250.470(f) under the changed well
design.
(d) You must conduct tests or
exercises of your SCCE, including
deployment of your SCCE, when
directed by the Regional Supervisor.
(e) You must maintain records
pertaining to testing, inspection, and
maintenance of your SCCE for at least
10 years and make the records available
to any authorized BSEE representative
upon request.
(f) You must maintain records
pertaining to the use of your SCCE
during testing, training, and deployment
activities for at least 3 years and make
the records available to any authorized
BSEE representative upon request.
(g) Upon a loss of well control, you
must initiate transit of all SCCE
identified in paragraph (a) of this
section to the well.
(h) You must deploy and use SCCE
when directed by the Regional
Supervisor.
§ 250.472 What are the relief rig
requirements for the Arctic OCS?
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(a) In the event of a loss of well
control, the Regional Supervisor may
direct you to drill a relief well using the
relief rig described in your APD. Your
relief rig must comply with all other
requirements of this part for drilling
operations, and it must be able to drill
a relief well under anticipated Arctic
OCS Conditions.
(b) When you are drilling below or
working below the surface casing during
Arctic OCS exploratory drilling
operations, you must have access to a
relief rig, different from your primary
drilling rig, staged in a location such
that it can arrive on site, drill a relief
well, kill and abandon the original well,
and abandon the relief well prior to
expected seasonal ice encroachment at
the drill site, but no later than 45 days
after the loss of well control.
(c) Operators may request approval of
alternative compliance measures to the
relief rig requirement in accordance
with § 250.141.
§ 250.473 What must I do to protect health,
safety, property, and the environment while
operating on the Arctic OCS?
In addition to the requirements set
forth in § 250.107, when conducting
exploratory drilling operations on the
Arctic OCS, you must protect health,
safety, property, and the environment
by using the following:
(a) Equipment and materials that are
rated or de-rated for service under
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conditions that can be reasonably
expected during your operations; and
(b) Measures to address human factors
associated with weather conditions that
can be reasonably expected during your
operations including, but not limited to,
provision of proper attire and
equipment, construction of protected
work spaces, and management of shifts.
■ 11. Amend § 250.1920 by:
■ a. Adding a new last sentence to
paragraphs (b)(5), (c), and (d); and
■ b. Adding new paragraphs (e) and (f)
to read as follows:
§ 250.1920 What are the auditing
requirements for my SEMS program?
*
*
*
*
*
(b) * * *
(5) * * * For exploratory drilling
operations taking place on the Arctic
OCS, you must conduct an audit,
consisting of an onshore portion and an
offshore portion, including all related
infrastructure, once per year for every
year in which drilling is conducted.
*
*
*
*
*
(c) * * * For exploratory drilling
operations taking place on the Arctic
OCS, you must submit an audit report
of the audit findings, observations,
deficiencies and conclusions for the
onshore portion of your audit no later
than March 1 in any year in which you
plan to drill, and for the offshore
portion of your audit, within 30 days of
the close of the audit.
(d) * * * For exploratory drilling
operations taking place on the Arctic
OCS, you must provide BSEE with a
copy of your CAP for addressing
deficiencies or nonconformities
identified in the onshore portion of the
audit no later than March 1 in any year
in which you plan to drill, and for the
offshore portion of your audit, within 30
days of the close of the audit.
(e) For exploratory drilling operations
taking place on the Arctic OCS, during
the offshore portion of each audit, 100
percent of the facilities operated must
be audited while drilling activities are
underway. The offshore portion of the
audit for each facility must be started
and closed within 30 days after the first
spudding of the well or entry into an
existing wellbore for any purpose from
that facility.
(f) For exploratory drilling operations
taking place on the Arctic OCS, if BSEE
determines that the CAP or progress
toward implementing the CAP is not
satisfactory, BSEE may order you to shut
down all or part of your operations.
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PART 254—OIL-SPILL RESPONSE
REQUIREMENTS FOR FACILITIES
LOCATED SEAWARD OF THE COAST
LINE
12. The authority citation for 30 CFR
part 254 continues to read as follows:
■
Authority: 33 U.S.C. 1321.
13. Amend § 254.6 by:
a. Revising the definition of ‘‘Adverse
weather conditions,’’
■ b. Adding a new definition for ‘‘Arctic
OCS’’ in alphabetical order, and
■ c. Adding a new definition for ‘‘Ice
intervention practices’’ in alphabetical
order.
■
■
§ 254.6
Definitions.
*
*
*
*
*
Adverse weather conditions means,
for the purposes of this part, weather
conditions found in the operating area
that make it difficult for response
equipment and personnel to clean up or
remove spilled oil or hazardous
substances. These conditions include,
but are not limited to: Fog, inhospitable
water and air temperatures, wind, sea
ice, extreme cold, freezing spray, snow,
currents, sea states, and extended
periods of low light. Adverse weather
conditions do not refer to conditions
under which it would be dangerous or
impossible to respond to a spill, such as
a hurricane.
Arctic OCS means the Beaufort Sea
and Chukchi Sea Planning Areas, as
described in the Proposed Final OCS Oil
and Gas Leasing Program for 2012–2017
(June 2012).
*
*
*
*
*
Ice intervention practices means the
equipment, vessels, and procedures
used to increase oil encounter rates and
the effectiveness of spill response
techniques and equipment when sea ice
is present.
*
*
*
*
*
14. Add § 254.55 to Subpart D to read
as follows:
§ 254.55 Spill response plans for facilities
located in Alaska State waters seaward of
the coast line in the Chukchi and Beaufort
Seas.
Response plans for facilities
conducting exploratory drilling
operations from a MODU seaward of the
coast line in Alaska State waters in the
Chukchi and Beaufort Seas must follow
the requirements contained within
subpart E of this part, in addition to the
other requirements of this subpart. Such
response plans must address how the
source control procedures selected to
comply with State law will be integrated
into the planning, training, and exercise
requirements of §§ 254.70(a), 254.90(a),
and 254.90(c) in the event that the
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proposed operations do not incorporate
the capping stack, cap and flow system,
containment dome, and/or other similar
subsea and surface devices and
equipment and vessels referenced in
those sections.
■ 15. Add new subpart E to read as
follows:
drilling activities, and all resulting
modifications must be submitted to the
Regional Supervisor. If this review does
not result in modifications, you must
inform the Regional Supervisor in
writing that there are no changes. The
requirements of this subsection are in
lieu of the requirements in § 254.30(a).
Subpart E—Oil-Spill Response
Requirements for Facilities Located on the
Arctic OCS
Sec.
254.65 Purpose.
254.66 through 254.69 [Reserved]
254.70 What are the additional
requirements for facilities conducting
exploratory drilling from a MODU on the
Arctic OCS?
254.71 through 254.79 [Reserved]
254.80 What additional information must I
include in the ‘‘Emergency response
action plan’’ section for facilities
conducting exploratory drilling from a
MODU on the Arctic OCS?
254.81 through 254.89 [Reserved]
254.90 What are the additional
requirements for exercises of your
response personnel and equipment for
facilities conducting exploratory drilling
from a MODU on the Arctic OCS?
§§ 254.71 through 254.79
Subpart E—Oil-Spill Response
Requirements for Facilities Located on
the Arctic OCS
§ 254.65
Purpose.
This subpart describes the additional
requirements for preparing spill
response plans and maintaining oil spill
preparedness for facilities conducting
exploratory drilling operations from a
MODU on the Arctic OCS.
§§ 254.66 through 254.69
[Reserved]
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
§ 254.70 What are the additional
requirements for facilities conducting
exploratory drilling from a MODU on the
Arctic OCS?
In addition to meeting the applicable
requirements of this part, your response
plan must:
(a) Describe how the relevant
personnel, equipment, materials, and
support vessels associated with the
capping stack, cap and flow system,
containment dome, and other similar
subsea and surface devices and
equipment and vessels will be
integrated into oil spill response
incident action planning;
(b) Describe how you will address
human factors, such as cold stress and
cold related conditions, associated with
oil spill response activities in adverse
weather conditions and their impacts on
decision-making and health and safety;
and
(c) Undergo plan-holder review prior
to handling, storing, or transporting oil
in connection with seasonal exploratory
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[Reserved]
§ 254.80 What additional information must
I include in the ‘‘Emergency response
action plan’’ section for facilities
conducting exploratory drilling from a
MODU on the Arctic OCS?
In addition to the requirements in
§ 254.23, you must include the
following information in the emergency
response action plan section of your
response plan:
(a) A description of your ice
intervention practices and how they
will improve the effectiveness of the oil
spill response options and strategies
that are listed in your OSRP in the
presence of sea ice. When developing
the ice intervention practices for your
oil spill response plan, you must
consider, at a minimum, the use of
specialized tactics, modified response
equipment, ice management assist
vessels, and technologies for the
identification, tracking, containment
and removal of oil in ice.
(b) On areas of the Arctic OCS where
a planned shore-based response would
not satisfy § 254.1(a):
(1) A list of all resources required to
ensure an effective offshore-based
response capable of operating in adverse
weather conditions. This list must
include a description of how you will
ensure the shortest possible transit
times, including but not limited to
establishing an offshore resource
management capability (e.g., sea-based
staging, maintenance, and berthing
logistics); and
(2) A list and description of logistics
resupply chains, including waste
management, that effectively factor in
the remote and limited infrastructure
that exists in the Arctic and ensure you
can adequately sustain all oil spill
response activities for the duration of
the response. The components of the
logistics supply chain include, but are
not limited to:
(i) Personnel and equipment transport
services;
(ii) Airfields and types of aircraft that
can be supported;
(iii) Capabilities to mobilize supplies
(e.g., response equipment, fuel, food,
fresh water) and personnel to the
response sites;
(iv) Onshore staging areas, storage
areas that may be used en route to
staging areas, and camp facilities to
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support response personnel conducting
offshore, nearshore and shoreline
response; and
(v) Management of recovered fluid
and contaminated debris and response
materials (e.g., oiled sorbents), as well
as waste streams generated at offshore
and on-shore support facilities (e.g.,
sewage, food, and medical).
(c) A description of the system you
will use to maintain real-time location
tracking for all response resources while
operating, transiting, or staging/
maintaining such resources during a
spill response.
§§ 254.81 through 254.89
[Reserved]
§ 254.90 What are the additional
requirements for exercises of your
response personnel and equipment for
facilities conducting exploratory drilling
from a MODU on the Arctic OCS?
In addition to the requirements in
§ 254.42, the following requirements
apply to exercises for your response
personnel and equipment for facilities
conducting exploratory drilling from a
MODU on the Arctic OCS:
(a) You must incorporate the
personnel, materials, and equipment
identified in § 254.70(a), the safe
working practices identified in
§ 254.70(b), the ice intervention
practices described in § 254.80(a), the
offshore-based response requirements in
§ 254.80(b), and the resource tracking
requirements in § 254.80(c) into your
spill-response training and exercise
activities.
(b) For each season in which you plan
to conduct exploratory drilling
operations from a MODU on the Arctic
OCS, you must notify the Regional
Supervisor 60 days prior to handling,
storing, or transporting oil.
(c) After the Regional Supervisor
receives notice pursuant to § 254.90(b),
the Regional Supervisor may direct you
to deploy and operate your spill
response equipment and/or your
capping stack, cap and flow system, and
containment dome, and other similar
subsea and surface devices and
equipment and vessels, as part of
announced or unannounced exercises or
compliance inspections. For the
purposes of this section, spill response
equipment does not include the use of
blowout preventers, diverters, heavy
weight mud to kill the well, relief wells,
or other similar conventional well
control options.
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CHAPTER V—BUREAU OF OCEAN
ENERGY MANAGEMENT, DEPARTMENT OF
THE INTERIOR
PART 550—OIL AND GAS AND
SULPHUR OPERATIONS IN THE
OUTER CONTINENTAL SHELF
16. The authority citation for 30 CFR
part 550 continues to read as follows:
■
Authority: 30 U.S.C. 1751; 31 U.S.C. 9701;
43 U.S.C. 1334.
17. Amend § 550.105 by adding new
definitions for ‘‘Arctic OCS’’ and
‘‘Arctic OCS conditions’’ in alphabetical
order to read as follows:
■
§ 550.105
Definitions.
*
*
*
*
*
Arctic OCS means the Beaufort Sea
and Chukchi Sea Planning Areas, as
described in the Proposed Final OCS Oil
and Gas Leasing Program for 2012–2017
(June 2012).
Arctic OCS conditions means, for the
purposes of this part, the conditions
operators can reasonably expect during
operations on the Arctic OCS. Such
conditions, depending on the time of
year, include, but are not limited to:
extreme cold, freezing spray, snow,
extended periods of low light, strong
winds, dense fog, sea ice, strong
currents, and dangerous sea states.
Remote location, relative lack of
infrastructure, and the existence of
subsistence hunting and fishing areas
are also characteristic of the Arctic
region.
*
*
*
*
*
■ 18. Amend § 550.200 paragraph (a) by
adding the term ‘‘IOP’’ in alphabetical
order:
§ 550.200
Definitions.
*
*
*
*
*
(a) * * *
IOP means Integrated Operations
Plan.
*
*
*
*
*
■ 19. Add a new § 550.204 to read as
follows:
mstockstill on DSK4VPTVN1PROD with PROPOSALS2
§ 550.204 When must I submit my IOP for
proposed Arctic exploratory drilling
operations and what must the IOP include?
If you propose exploratory drilling
activities on the Arctic OCS, you must
submit an Integrated Operations Plan
(IOP) to the Regional Supervisor at least
90 days prior to filing your EP. Your IOP
must describe how your exploratory
drilling program will be designed and
conducted in an integrated manner
suitable for Arctic OCS Conditions and
include the following information:
(a) Information describing how all
vessels and equipment will be designed,
built, and/or modified to account for
Arctic OCS Conditions;
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(b) A schedule of your exploratory
drilling program, including contractor
work on critical components of your
program;
(c) A description of your mobilization
and demobilization operations,
including tow plans suitable for Arctic
OCS Conditions, as well as your general
maintenance schedule for vessels and
equipment;
(d) A description of your exploratory
drilling program objectives and
timelines for each objective, including
general plans for abandonment of the
well(s), such as:
(1) Contingency plans for temporary
abandonment in the event of ice
encroachment at the drill site;
(2) Plans for permanent abandonment;
and
(3) Plans for temporary seasonal
abandonment;
(e) A description of your weather and
ice forecasting capabilities for all phases
of the exploration program, including a
description of how you would respond
to and manage ice hazards and weather
events;
(f) A description of work to be
performed by contractors supporting
your exploration drilling program
(including mobilization and
demobilization), including:
(1) How such work will be designed
or modified to account for Arctic OCS
Conditions; and
(2) Your concepts for contractor
management, oversight, and risk
management.
(g) A description of how you will
ensure operational safety while working
in Arctic OCS Conditions, including but
not limited to:
(1) The safety principles that you
intend to apply to yourself and your
contractors;
(2) The accountability structure
within your organization for
implementing such principles;
(3) How you will communicate such
principles to your employees and
contractors; and
(4) How you will determine
successful implementation of such
principles.
(h) Information regarding your
preparations and plans for staging of oil
spill response assets;
(i) A description of your efforts to
minimize impacts of your exploratory
drilling operations on local community
infrastructure, including but not limited
to housing, energy supplies, and
services; and
(j) A description of whether and to
what extent your project will rely on
local community workforce and spill
cleanup response capacity.
■ 20. Revise § 550.206 to read as
follows:
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§ 550.206 How do I submit the IOP, EP,
DPP, or DOCD?
(a) Number of copies. When you
submit an IOP, EP, DPP, or DOCD to
BOEM, you must provide:
(1) Four copies that contain all
required information (proprietary
copies);
(2) Eight copies for public distribution
(public information copies) that omit
information that you assert is exempt
from disclosure under the Freedom of
Information Act (FOIA) (5 U.S.C. 552)
and the implementing regulations (43
CFR part 2); and
(3) Any additional copies that may be
necessary to facilitate review of the IOP,
EP, DPP, or DOCD by certain affected
States and other reviewing entities.
(b) Electronic submission. You may
submit part or all of your IOP, EP, DPP,
or DOCD and its accompanying
information electronically. If you prefer
to submit your IOP, EP, DPP, or DOCD
electronically, ask the Regional
Supervisor for further guidance.
(c) Withdrawal after submission. You
may withdraw your proposed IOP, EP,
DPP, or DOCD at any time for any
reason. Notify the appropriate BOEM
OCS Region if you do.
■ 21. Amend § 550.220 by:
■ a. Revising paragraph (a), and
■ b. Adding a new paragraph (c).
§ 550.220 If I propose activities in the
Alaska OCS Region, what planning
information must accompany the EP?
*
*
*
*
*
(a) Emergency Plans. A description of
your emergency plans to respond to a
fire, explosion, personnel evacuation, or
loss of well control, as well as a loss or
disablement of a drilling unit, and loss
of or damage to a support vessel,
offshore vehicle, or aircraft.
*
*
*
*
*
(c) If you propose exploration
activities on the Arctic OCS, the
following planning information must
also accompany your EP:
(1) Suitability for Arctic OCS
conditions. A description of how your
exploratory drilling activities will be
designed and conducted in a manner
suitable for Arctic OCS conditions and
how such activities will be managed
and overseen as an integrated endeavor.
(2) Ice and weather management. A
description of your weather and ice
forecasting and management plans for
all phases of your exploratory drilling
activities, including:
(i) A description of how you will
respond to and manage ice hazards and
weather events;
(ii) Your ice and weather alert
procedures;
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(iii) Your procedures and thresholds
for activating your ice and weather
management system(s); and
(iv) Confirmation that you will
operate ice and weather management
and alert systems continuously
throughout the planned operations,
including mobilization and
demobilization operations to and from
the Arctic OCS.
(3) Source control and containment
equipment capabilities. A general
description of how you will comply
with § 250.471 of this title.
(4) Deployment of a relief well rig. A
general description of how you will
comply with § 250.472 of this title,
including a description of the relief well
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rig, the anticipated staging area of the
relief well rig, an estimate of the time it
would take for the relief well rig to
arrive at the site of a loss of well control,
how you would drill a relief well if
necessary, and the approximate
timeframe to complete relief well
operations.
(5) Resource-sharing. Any agreements
you have with third parties for the
sharing of assets or the provision of
mutual aid in the event of an oil spill
or other emergency.
(6) Anticipated end of seasonal
operations dates. Your projected end of
season dates, and the information used
to identify those dates, for:
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9971
(i) The completion of on-site
operations, which is contingent upon
your capability in terms of equipment
and procedures to manage and mitigate
risks associated with Arctic OCS
Conditions; and
(ii) The termination of drilling
operations into zones capable of flowing
liquid hydrocarbons to the surface
consistent with the relief rig planning
requirements under § 250.472 of this
title and with your estimated timeframe
under paragraph (c)(4) of this section for
completion of relief well operations.
[FR Doc. 2015–03609 Filed 2–20–15; 4:15 pm]
BILLING CODE 4310–VH–4310–MR–P
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